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SOUTHWEST POWER POOL ANNUAL LOOKING FORWARD REPORT Prepared by: Boston Pacific Company, Inc. As an Independent Advisor to the SPP Board of Directors Craig R. Roach, Ph.D. Vincent Musco Sam Choi Andrew Gisselquist
2013
1100 New York Avenue, NW, Suite 490 East Washington, DC 20005
[email protected] www.bostonpacific.com
April 23, 2013
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TABLE OF CONTENTS I. Executive Summary ............................................................................................................. 1
II. The Shale Gas Revolution (An Update) ............................................................................... 8
A. The Shale Gas Revolution is Alive and Well ................................................................... 9
B. It Also is An Economic Revolution ............................................................................... 12
C. Assessing Environmental Concerns ............................................................................... 14
D. To Export or Not To Export? ......................................................................................... 17
III. EPA’s Continued Campaign on Coal (An Update) ........................................................... 22
A. Upcoming EPA Regulations .......................................................................................... 22
B. U.S. Greenhouse Gas Emissions Profile ........................................................................ 29
C. A Relevant Example....................................................................................................... 31
IV. Developments Driving the Future of Transmission Planning ........................................... 33
A. FERC Order No. 1000 .................................................................................................... 34
B. Scrutiny of the Costs and Benefits of Transmission Expansion .................................... 37
C. A Potential Breakthrough in HVDC Technology .......................................................... 38
D. Cybersecurity ................................................................................................................. 39
E. Integration of Distributed Generation ............................................................................ 41
V. The Future of U.S. Electricity Bills: Flat Demand, Rising Rates? .................................... 43
A. U.S. Demand for Electricity ........................................................................................... 45
B. Natural Gas Prices .......................................................................................................... 46
C. Interest Rates .................................................................................................................. 47
D. Utility Capital Expenditures: Upgrading the Grid ......................................................... 48
E. Utility Capital Expenditures: Environmental Compliance Costs ................................... 48
F. Pension Obligations........................................................................................................ 49
VI. Electric Vehicles (Update) ................................................................................................. 51
VII. Distributed Generation as a Component of Demand Response ......................................... 54
VIII. Other Strategic Issues of Note ........................................................................................... 58
A. Dodd-Frank .................................................................................................................... 59
B. Future of Nuclear Power (An Update) ........................................................................... 59
C. Drivers Toward a Less-Centralized Grid ....................................................................... 62
LIST OF TABLES AND FIGURES............................................................................................. 63
GLOSSARY ................................................................................................................................. 64
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ABOUT BOSTON PACIFIC COMPANY, INC.
Boston Pacific Company, Inc. is a consulting and investment services firm, located in Washington, D.C., specializing in the electricity and natural gas industries. For 26 years we have provided information and insight to our clients who span the full range of stakeholders: state regulatory commissions, regional transmission organizations, energy consumers, competitive power producers, electric utilities, gas pipeline companies, and electric transmission companies. We are nationally recognized experts on the electricity business as documented by our service as expert witnesses throughout North America. Boston Pacific also is an industry leader in designing and monitoring major power procurements of every type for state commissions across the country, as well as open seasons for merchant transmission lines. In addition, Boston Pacific has extensive, hands-on experience with a full range of power technologies including clean coal on- and off-shore wind, geothermal, waste-to-energy, solar photovoltaics, and natural gas-fired combined-cycle. For nine years we have served as an independent advisor to the Board of Directors of the Southwest Power Pool RTO on a full range of issues related to market design and operation.
For more information on Boston Pacific please visit us at www.bostonpacific.com.
DISCLAIMER
The data and analysis in this report are provided for informational purposes only and shall not be considered or relied upon as market advice. Boston Pacific makes no representations or warranties of any kind, express or implied, with respect to the accuracy or adequacy of the information contained herein. Boston Pacific shall have no liability to recipients of this information or third parties for the consequences arising from errors or discrepancies in this information, for recipients’ or third parties’ reliance upon such information, or for any claim, loss or damage of any kind or nature whatsoever arising out of or in connection with (1) the deficiency or inadequacy of this information for any purpose, whether or not known or disclosed to the authors, (2) any error or discrepancy in this information, (3) the use of this information, or (4) any loss of business or other consequential loss or damage whether or not resulting from any of the foregoing.
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I. Executive Summary
his is the third year in which Boston Pacific Company, Inc. (Boston Pacific) has prepared a separate Annual Looking Forward Report for the Southwest Power Pool (SPP) Board of Directors. This report is intended to contribute to the longer-
term strategic planning by the board. To that end, we focus on broad market and regulatory events that (a) potentially could have a significant impact on SPP’s markets and/or (b) could require the board’s special attention. First, we update the board on four topics: the shale gas revolution, U.S. Environmental Protection Agency’s (EPA) campaign on coal, the prospects for electric vehicles (EVs), and the potential for new nuclear power plants. Second, we were asked to comment on a wide range of strategic issues: factors driving the future of transmission planning, the future of U.S. monthly electric bills, issues related to distributed generation resources, Dodd-Frank legislation, and the concept of a less-centralized grid.
Boston Pacific very much appreciates the input to and guidance for this report provided by the board’s Oversight Committee.
T
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A. The Shale Gas Revolution (An Update)
In our two previous Annual Looking Forward Reports we announced the sudden emergence of the shale gas revolution and documented its game-changing impact. We quantified the dramatic decrease in natural gas prices from their peaks in 2008, as well as the dramatic increase in available natural gas supply here at home. Indeed, reserve estimates for U.S. natural gas have increased so much that the prevailing wisdom has been reversed. Just five years ago the popular belief was that America would grow increasingly dependent on natural gas imports in the form of liquefied natural gas (LNG). Today, we believe the exact opposite – America might export some of its natural gas as LNG.
The shale gas revolution matters to the SPP Board primarily because the price of natural gas so often drives the price of electricity in SPP’s energy market. Put bluntly, the board wants to know whether the promised price benefits of the shale gas revolution will be realized. Or has the quantity of accessible reserves been greatly overstated resulting in prices that would be much higher than expected? In addition, we all want to know whether environmental concerns should and could stop the revolution in its tracks.
In this year’s report, we divide our discussion into four parts. First, we provide some new, confirming data from IHS Global (IHS) which shows the revolution is alive and well; that is, significant increases in shale gas production are expected at stable prices, and the share of electricity generated by natural gas is expected to increase substantially. The most recent forecast from the U.S. Energy Information Administration (EIA) also confirms that the revolution will continue, although its details differ from those of IHS.
Second, we show how the discussion of the impact of the shale gas revolution has shifted from the narrow view of its impact on natural gas prices to a much broader view of its impact on the American economy. Indeed, the discussion now is more in terms of an economic revolution with significant increases in jobs and the revitalization of America's industrial base. This discussion is often offered as a counterweight to claims of environmental concern.
Third, we update the continuing debate on the potential environmental impact of the shale gas revolution with a focus on two questions. One, does shale gas-fired electricity generation, when assessed across its full fuel cycle, actually decrease global climate change emissions as compared to coal-fired power? The answer is, yes, from a collaborative task force study funded by the National Renewable Energy Laboratory. Two, what do we know about the effects of shale gas production on water quality? The answer from the EPA is essentially not enough, yet, but we will have answers in 2014 after an expansive, data-rich, scientific study led by the EPA is released.
Fourth, will allowing exports undermine the net economic benefits of the shale gas revolution? The answer is, no, according to a study conducted for the U.S. Department of Energy (DOE) by NERA Economic Consulting (NERA). The NERA study reports that, across all the many scenarios studied, there are net economic benefits from increased LNG exports. It is true that, with exports, the wellhead price of natural gas in America will be higher than without exports. However, NERA finds that this negative economic effect is entirely offset by the positive economic effect of higher export revenues for natural gas as well as the revenue from the liquefaction itself.
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Importantly, NERA explains that American LNG exports will have to earn their way into Asian and other markets. That is, exports are not guaranteed at any price; if shale gas is more limited than now thought, prices will be too high to allow American LNG exports. More broadly, the point is that the future of American natural gas, at home and abroad, depends most heavily on the nature of the underlying resources.
B. EPA’s Continued Campaign On Coal
The electricity industry continues to be shaped by environmental regulations and nowhere is that more evident than with what can be fairly characterized as the EPA’s ongoing “campaign on coal.” The EPA is implementing a long list of both new and old regulations that could lead to the retirement of coal-fired power plants (and others) because they would require costly retrofits. That list includes the Mercury and Air Toxics Standards (MATS), the Regional Haze rule, regular updates to National Ambient Air Quality Standards, new regulations on water usage and coal waste and, perhaps most notably, regulations on greenhouse gas (GHG) emissions such as CO2.
For many, EPA’s campaign is provocative because it is being implemented without additional congressional action. EPA is relying instead on the existing Clean Air Act, Clean Water Act, and Resource Conservation and Recovery Act authority. These regulations – combined with low natural gas prices, a weakened economy, state-sponsored regional GHG cap-and-trade programs, and state renewable portfolio standards (RPS) – may result in permanent reductions in coal capacity and generation of coal-fired electricity. Indeed, driven by low natural gas prices, as well as environmental regulation to some extent, the EIA reports that coal-fired electricity generation in 2012 was about 25 percent lower than it had been in 2007. The Brattle Group has estimated that one-quarter of all U.S. coal capacity may be retiring in the next few years. The longer-term impact of this trend towards reduced emissions was captured in an October 2012 report from the think-tank Resources for the Future (RFF), which concluded that the U.S. may be on track to meet President Obama’s goal of reducing GHG emissions by 17 percent from 2005 levels by 2020. Again, these efforts are being made without any new action from Congress.
Utilities are facing this new landscape in different ways. One SPP-area utility can be cited as an example: the Public Service Company of Oklahoma (PSO) has responded by negotiating with EPA to be able to install less expensive retrofits in exchange for retiring its coal plants before the end of their useful life.
C. Developments Driving the Future of Transmission Planning
One of the most important roles SPP (and its board) play is planning the expansion of the transmission grid. Looking forward, SPP’s role in transmission planning and expansion is only expected to intensify in importance. Herein, we identify and provide commentary on five potential drivers that are shaping or may shape the future of transmission planning. We note that this is a new topic for the Annual Looking Forward Report.
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The first driver we consider is FERC’s Order No. 1000. Although issued in July 2011, the effects of FERC’s Order No. 1000, the agency’s latest policy directive related to transmission access, are only beginning to take shape. Order No. 1000 requires transmission plans to incorporate public policy benefits, develop cost allocation procedures, and remove the incumbent transmission owners’ right of “first refusal” in building new projects. Order No. 1000’s directive to remove the right of first refusal from open access transmission tariffs represents a milestone in competitive reform because it could open transmission investment to competition, much like the Public Utility Regulatory Policies Act in 1978 opened (perhaps inadvertently) generation investment to competition. However, as we explain, the true impact of FERC’s directive will likely be determined by the states, some of which are considering state-level right of first refusal laws. The order’s requirement that transmission providers engage in transmission planning with their neighbors, so-called interregional transmission planning, means that neighboring control areas will be required to plan multi-state, multi-jurisdiction transmission projects more efficiently, and to have a cost-sharing mechanism in place to get the projects funded. This, too, is a substantial change and could be especially relevant over the long-term for SPP with its largest neighbor, the Midwest ISO, as it absorbs the Entergy system into its footprint.
The second potential driver that we discuss is potential consumer backlash related to the cost of transmission expansion as it relates to economic, reliability, and public policy transmission projects. While we have not seen widespread pushback by end users, we will cite one instance involving utility pushback. A Midwestern utility has filed a complaint at FERC alleging that it has paid $170.5 million in transmission expansion costs to connect wind power to the grid from which it has received no benefits. This case is a direct challenge by a transmission customer to a FERC-approved method for allocating the costs of transmission expansion in an organized market; this method requires commensurate benefits. If granted by FERC, which has yet to act, the complaint could become a precedent and template for other utilities to use to challenge transmission cost allocation at FERC.
The final three drivers we consider are less direct than the first two, but could have some impact on transmission planning going forward. The third driver is a technological breakthrough with high voltage direct current (HVDC) transmission technology. Specifically, Swiss-based ABB recently claimed to have developed a HVDC circuit breaker, which if commercialized, could allow for increased integration of HVDC transmission into existing alternating current (AC) grids, or even build-outs of HVDC grids. Transmission planning processes, including SPP’s, should be flexible enough to accommodate the growth of HVDC projects if commercialization of a HVDC circuit breaker is achieved; HVDC transmission can bring lower capital costs and lower transmission losses.
A fourth driver in transmission planning is the growing importance of cybersecurity for critical electricity infrastructure assets. As the grid becomes more sophisticated, the threats it faces also become more sophisticated. Recent cyber attacks and the president’s adoption of cybersecurity guidelines demonstrate the seriousness of this issue. The electricity sector is ahead of other industries in creating standards; transmission providers already are implementing NERC standards on cybersecurity. However, as suggested in a recent NARUC report, electricity infrastructure planners and operators should consider cybersecurity standards as a minimum level of compliance, and search for areas not covered by standards or additional proactive security measures.
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The fifth potential driver that we discuss, although far from a new concept, is an expanded role for distributed generation, a topic covered in even more depth in chapters VII and VIII of this report. Transmission providers typically allow distributed generation to compete alongside other generation and demand-side resources in serving as alternatives to transmission solutions. For example, in PJM, distributed generation assumptions are developed in the transmission expansion plan, and distributed generation can be proposed to obviate the need for some transmission solutions identified in the transmission expansion plan. Similarly, in the Pacific Northwest, the utility PacifiCorp allows distributed generation to compete on an even footing against other generation, demand-side, and transmission solutions. SPP, for its part, is already in a good position to include any increase in distributed generation into its transmission and resource planning processes.
D. The Future of U.S. Electricity Bills: Flat Demand, Rising Rates?
A new topic for this year’s Annual Looking Forward Report is the potential for increases in the electricity bills, on average, for U.S. ratepayers. Our discussion in this chapter does two things. First, we provide data that shows that, on average, the U.S. electricity customer has enjoyed almost flat electricity bills in recent years and we note some anecdotal factors that have helped to keep bills from rising, such as weak economic growth and low natural gas prices. Second, we explain that the conditions of recent years may be changing and could produce cost increases that could drive electricity bills higher, even if demand for electricity stays flat. Those conditions include rising natural gas prices, increased capital expenditures in the utility industry, higher interest rates, and reduced public subsidies for electricity infrastructure. Our purpose is not to forecast future retail rates, nor model the impacts of changes in natural gas prices or electricity demand on average U.S. electricity bills. Rather, our purpose is only to present the idea that increases in electricity bills could be on the horizon; to that end, we use a report from Deloitte, other anecdotal data, and credible forecasts of key variables that often impact electricity rates.
E. Electric Vehicles (Update)
As an update to last year’s Annual Looking Forward Report, anecdotal evidence continues to suggest slower than expected EV penetration. As a result, the Obama administration is backing off from its goal of 1 million EVs by 2015. Sales data also shows that EVs remain on the periphery in the U.S. automobile market with sales accounting for less than one-half of 1 percent of total automobile sales. For perspective, in the 2011 Annual Looking Forward Report, it was projected that SPP’s share of total EVs would be 3 percent by the time 1 million EVs were on the road, resulting in a very small increase in system load. The potential for a demand shock appears even less likely today.
In last year’s Annual Looking Forward Report, one of our conclusions on the prospects for EVs was that their life-cycle cost may become competitive with conventional vehicles, especially if government subsidies are considered. We note, however, that the federal tax credit for the purchase of new EVs is set to phase out once manufacturers hit a specific production target. This could pose a challenge, even if prices for EVs decline over time. In addition, other
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issues that we identified last year, such as “range anxiety” and a lack of infrastructure are hurdles that still remain.
Since EVs may not be making much headway in the U.S., their future may rest with China, which is making an aggressive push to become a leader in EVs. China is focusing on EVs for a number of significant and varied reasons: (a) to ‘leapfrog’ foreign rivals in the automobile market, (b) to reduce the country’s dependency on foreign oil, and (c) to reduce pollution, including CO2 emissions. China’s promotion of EVs is also more ambitious than that of the U.S. For example, China is targeting 5 million EVs by 2020 and in some cases is offering a subsidy for EVs that is more than double the tax credit offered in the U.S. In addition, Chinese companies have been eager to acquire financially unsuccessful U.S. EV and battery businesses.
Even with China’s more aggressive actions, however, the near-term future of the industry may not be bright. EV sales have not taken off in China, and China faces some of the same problems that have hampered penetration in the U.S. However, unlike the U.S., China does have factors like the severe, well-publicized pollution episodes that may be the impetus for EVs to gain traction there. If there is potential for an eventual electricity demand shock in the U.S. from EVs, it is possible that it will start with cheaper EV imports from China.
F. Distributed Generation as a Component of Demand Response
We first pointed out that demand response would grow in coming years in the 2011 Annual Looking Forward Report, noting the impact of the Integrated Marketplace launch on opportunities for demand-side participation at the wholesale level. In its most recent long-term reliability assessment, NERC also projects significant growth in demand response in SPP. Specifically, NERC sees an increase in total SPP demand response of 59.2 percent between 2013 and 2022, growing to 2,408 MW in total. As a result, demand response resources will be the equivalent of about 4 percent of total internal demand in 2022. In short, demand response in SPP is here to stay, and since the costs, benefits, and implications of the different types of demand response and distributed generation can vary significantly, it is important that the board require granular data on demand-side participation. This will provide the board with a better understanding of the demand-side resources being attracted to participate in its markets, and to design or improve efforts by SPP and its stakeholders to attract new investment in demand response and distributed generation consistent with SPP’s overall cost, reliability, and environmental objectives.
More granular data will reveal that not all demand response is the same. Some demand response responds to price signals, while other demand response is called upon in times of reliability emergencies. Some demand response is actually generation – “distributed” generation – which refers to “relatively small-scale generators that produce several kilowatts . . . to tens of megawatts . . . of power and are generally connected to the grid at the distribution or substation levels.” Moreover, different distributed generation technologies differ in reliability and environmental performance – think of the differences between diesel engines and solar roof panels as an example of two types of distributed generation.
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G. Other Strategic Issues of Note
The closing chapter of this year’s Annual Looking Forward Report takes a brief look at three other strategic issues for the board’s consideration. The first is the impact of the CFTC’s implementation of Dodd-Frank on the electricity industry. Thanks to broad language in Dodd-Frank and CFTC regulations, utilities may now have to comply with CFTC regulations on traditional electricity products ranging from spot energy to financial transmission rights. This is because these are getting swept up in regulations related to financial derivative products.
The second strategic issue considers the future of the nuclear power industry, both in the U.S. and abroad. Domestically, we see some early-stage evidence of movement on the modular nuclear investment front, with a recent DOE-funded project moving forward. Abroad, we see China (and others) leading the way in new nuclear development to meet growing demand and to mitigate health-threatening environmental conditions. China also appears to have brushed aside post-Fukushima safety fears after a short assessment.
The third strategic issue concerns the factors driving the U.S. toward a less-centralized electric grid. In a brief summing up, we conclude that cybersecurity costs and fears, weather-related damage and outages, and rising retail rates can all create incentives for a less-centralized electric grid.
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II. The Shale Gas Revolution (An Update)
n our two previous Annual Looking Forward Reports we announced the sudden emergence of the shale gas revolution and documented its game-changing impact. We quantified the dramatic decrease in natural gas prices, from their peaks in 2008,
as well as the dramatic increase in available natural gas supply here at home. Indeed, reserve estimates for U.S. natural gas have increased so much that the prevailing wisdom has been reversed. Just five years ago the popular belief was that America would grow increasingly dependent on natural gas imports in the form of LNG. Today, we believe the exact opposite – America might export some of its natural gas as LNG.
The shale gas revolution matters to the SPP Board primarily because the price of natural gas so often drives the price of electricity in SPP’s energy market. Put bluntly, the board wants to know whether the promised price benefits of the shale gas revolution will be realized. Or has the quantity of accessible reserves been greatly overstated resulting in prices that would be much higher than expected? In addition, we all want to know whether environmental concerns should and could stop the revolution in its tracks.
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In this year’s report, we divide our discussion into four parts. First, we provide some new, confirming data from IHS which shows the revolution is alive and well; that is, significant increases in shale gas production are expected at stable prices, and the share of electricity generated by natural gas is expected to increase substantially.
Second, we show how the discussion of the impact of the shale gas revolution has shifted from the narrow view of its impact on natural gas prices to a much broader view of its impact on the American economy. Indeed, the discussion now is more in terms of an economic revolution with significant increases in jobs and the revitalization of America's industrial base. This discussion is often offered as a counterweight to claims of environmental concern.
Third, we update the continuing debate on the potential environmental impact of the shale gas revolution with a focus on two questions. One, does shale gas-fired electricity generation, when assessed across its full-fuel cycle, actually decrease global climate change emissions as compared to coal-fired power? The answer is, yes, from a collaborative task force study funded by the National Renewable Energy Laboratory. Two, what do we know about the effects of shale gas production on water quality? The answer from the EPA is essentially not enough, yet, but we will have answers in 2014 after an expansive, data-rich, scientific study led by the EPA is released.
Fourth, we address the high-profile issue of whether allowing exports will result in a net economic benefit. According to a study conducted for the DOE by NERA, the answer is that a positive, though small, net economic benefit is achieved by exporting natural gas across a wide range of scenarios.1
Importantly, NERA explains that American LNG exports will have to earn their way into Asian and other markets. That is, exports are not guaranteed at any price; if shale gas is more limited than now thought, prices will be too high to allow American LNG exports. More broadly, the point is that the future of American natural gas, at home and abroad, depends most heavily on the nature of the underlying shale gas resources.
It is true that, with exports, the wellhead price of natural gas in America will be higher than without exports. However, NERA finds that this negative economic effect is entirely offset by the positive economic effect of higher export revenues for natural gas as well as the revenue from the liquefaction itself.
A. The Shale Gas Revolution is Alive and Well
Although its ultimate goal was to quantify the economic impact of the expansion of both unconventional oil and natural gas (including shale gas) production and use, IHS’s study does include a forecast of a robust expansion of shale gas production, and an increase in its use for electricity generation.2
1 NERA Economic Consulting, Macroeconomic Impacts of LNG Exports from the United States, 2012, 1.
To start, IHS reminds us that unconventional natural gas means only that the gas is produced in new or unconventional ways – the natural gas (or oil) itself is the same
2 IHS Global, America’s New Energy Future: The Unconventional Oil and Gas Revolution and the US Economy-Volume 1: National Economic Contributions, October 2012.
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commodity produced with conventional means.3 And, further, that shale gas is one of three types of production in the unconventional category – the category also includes “tight gas” and “coal bed methane.”4 IHS reports that total natural gas production in America is now 65 billion cubic feet per day (Bcf) and that 50 percent of this total is from shale and tight gas.5 By 2035, IHS sees an even larger role for unconventional gas. Total natural gas production in America will grow to 100 Bcf, an increase from today of 54 percent. Of that 100 Bcf total, IHS forecasts that 80 percent will come from shale and tight gas.6 Of the total 80 Bcf of unconventional gas in 2035, 54 Bcf or two-thirds will come from shale gas. That means shale gas production is forecasted by IHS to increase from 2012 to 2035 by a total of 127 percent.7
In terms of the increase in natural gas consumption, IHS sees that much of the increase will be traced to the electricity business.
8 As expected, the greater use of natural gas in the electricity business is driven (a) by economics – its price is low, (b) environmental regulations – leading to the retirement of coal-fired power plants and the need to replace them with gas-fired facilities, and (c) policies to promote renewable energy – natural gas power plants are needed to accommodate the intermittent production from renewable energy like wind and other renewables.9
As to price, IHS sees a substantial increase from the lows in 2012 to 2015; in real terms (that is, excluding economy-wide inflation) prices at Henry Hub increase from $2.57/MMBtu to $4.37/MMBtu. Thereafter, however, the price for natural gas at Henry Hub is forecasted to be quite stable; again, in real terms it increases by about seven-tenths of 1 percent each year from $4.37/MMBtu in 2015 to $5.07/MMBtu in 2035.
10 As to use of natural gas for electricity, IHS forecasts a need for 500 GW of new electric generation capacity in the period from 2012 to 2035. Of that total 53 percent will use natural gas, 40 percent will be wind or solar, 5 percent will be nuclear, and 2 percent will be advanced coal.11
In its early release forecast in 2013, the EIA also gives some support to the finding that the shale gas revolution is alive and well. For example, of the total increase in primary energy production in America of all sorts (oil, coal, etc.) from 2010 to 2040, the increase in natural gas production alone accounts for 52 percent of the total increase.
12 EIA also finds that the share of electricity generation taken by natural gas increases from about 24 percent in 2010 to 30 percent by 2040.13
3 Ibid., 2.
With respect to price, while EIA shows stable prices into 2025, the increases
4 Ibid., 15. 5 Ibid. 6 Ibid. 7 Ibid., 19. 8 Ibid., 16. 9 Ibid. 10 Ibid., 19. 11 Ibid., 16. 12 U.S. Energy Information Administration, Annual Energy Outlook 2013 Early Release Overview, December 5, 2012, 15. 13 Ibid., 1.
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thereafter are much higher than that forecasted by IHS. The EIA forecasts prices at Henry Hub in real terms to grow by 3.2 percent per year from 2025 to 2040.14
For near-term price expectations, we also looked at NYMEX price futures. Note that these are in nominal terms – that is, they include expectations for economy-wide inflation – rather than in real terms as with IHS and EIA. Note, too, that, in reality, the NYMEX futures price is stated for each month and we have calculated a simple average of those prices to get an annual price. Figure II.1 displays the average annual futures price for each year from 2013 to 2025 on two trade dates. The term “trade date” refers to the date on which the price expectation was set; our two trade dates are February 21, 2012 and February 21, 2013.
FIGURE II.1
NYMEX Futures Prices for the 2013 to 2025 Period On Two Trade Dates (Nominal Dollars per MMBtu)
Source: Boston Pacific using data from CME Group’s NYMEX.
The figure helps make two points. First, price expectations are just about the same for
this year and last year – that is, expectations have been rather stable. Second, the figure shows that prices are not expected to stay at their current, low levels. For example, for this year’s trade date (February 21, 2013), the nominal future price in 2024 is expected to be $6.69/MMBtu which would reflect over the previous 10 years an average annual nominal increase of 5.4 percent per year.
14 Ibid., 16.
$0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00
2013 2015 2017 2019 2021 2023 2025
$/M
MB
tu
February 21, 2012 February 21, 2013
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B. It Also is An Economic Revolution
As already noted, the primary message from the IHS forecasts is that the shale gas revolution also is an economic revolution. That is, there will be significant and continuing investment in production infrastructure that will create millions of new jobs, generate billions of dollars in value added, and pay billions of dollars in state and federal taxes. IHS provides estimates of the economic impact of both unconventional oil and natural gas production, but we focus herein only on unconventional gas. IHS’s specific findings include:
• “Close to $3.0 trillion in capital expenditures will take place between 2012 and 2035 in unconventional natural gas activity” (“unconventional natural gas” refers to both shale gas and tight gas). Of that total, $1.9 trillion is for shale gas and nearly $1 trillion is for tight gas.15
• “Over 2.1 million jobs will be created from unconventional gas activity between 2012 and 2035.” This includes direct, indirect and induced employment.
16
• Unconventional gas activity will contribute over $225 billion to the U.S. Economy by 2020. By 2035, this contribution will increase to $287 billion (on an annual basis).
17
• From 2012 – 2035, unconventional gas activity will generate $635 billion in federal tax revenue; $700 billion will be generated for state and local taxes. Total government revenue will exceed $1.3 trillion in that same period.
18
In regard to the all-important jobs impact, direct jobs mean those involved directly in the production activity. Indirect refers to jobs created by suppliers of equipment and services to the shale gas production business. Induced means jobs created as the people who hold the direct and indirect jobs spend their salaries. Table II.1 provides a breakdown for IHS’s estimate of direct, indirect, and induced jobs.
TABLE II.1
U.S. Lower 48 Employment Contribution from Unconventional Gas Activity (Number of Workers)
Source: IHS Global, America’s New Energy Future, 27.
15 IHS Global, National Economic Contributions, 20. 16 Ibid., 27. 17 Ibid., 31. 18 Ibid., 35.
Direct Indirect Induced Total2012 187,360 277,888 437,427 902,6752015 263,288 399,379 638,511 1,301,1782020 334,808 503,011 801,362 1,639,1812035 436,773 645,696 1,026,012 2,108,481
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As can be seen from Table II.1, in 2035, direct jobs account for about 20 percent of the total, indirect jobs are about 31 percent of the total, and induced jobs account for 49 percent of the total.
IHS also showed the jobs impact by state. In Table II.2, we list the jobs impact for the states represented in the SPP RTO; jobs for the entire state are shown, not just for the portion of the state within the SPP RTO, which is especially important when viewing the total for Texas. Also important is that the jobs impacts include both unconventional oil and natural gas production.
TABLE II.2
U.S. State-Level Employment Contribution of Unconventional Oil and Gas Summary (Number of Workers) for SPP Member States
Source: IHS Global, America’s New Energy Future, 22.
As can be seen in Table II.2, and as expected, 54 percent of the contributive jobs in the
SPP states in 2035 are in the state of Texas. Another 17 percent are in Oklahoma and 11 percent of the SPP state total is in Louisiana.
Table II.3 displays the added tax revenue IHS estimates being contributed by unconventional gas activity. Note that these estimates are in real terms – they exclude economy-wide inflation. For the period 2012 to 2035, the cumulative federal tax revenue is approximately $635 billion; federal royalty payments add approximately another $25 billion. The cumulative tax revenue to state and local governments is approximately $700 billion. By any measure, these are significant amounts.
2012 2020 2035Arkansas 33,100 52,539 56,418Kansas 11,032 25,340 43,959Louisiana 78,968 97,418 150,903Missouri 37,716 64,228 70,794Nebraska 6,261 10,483 11,287New Mexico 23,625 29,849 58,466Oklahoma 65,325 149,617 225,387Texas 576,084 929,482 733,179
Total 832,111 1,358,956 1,350,393
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TABLE II.3
Contribution from Unconventional Gas Activity to U.S. Lower 48 Government Revenue (Millions of 2012$)
Source: IHS Global, America’s New Energy Future, 35. Note: S & L denotes “State and Local.”
C. Assessing Environmental Concerns
1. Net Greenhouse Gas Emissions
Natural gas-fired combined-cycle power plants emit less than 50 percent of the GHGs than conventional coal-fired power plants. However, it has been alleged that if the GHG emissions from shale gas production are included, natural gas-fired power plants are no better than coal. The Joint Institute for Strategic Energy Analysis (JISEA), a collaboration funded by the DOE’s Renewable Energy Laboratory, assessed this allegation.19
Researchers analyzed data from more than 16,000 individual sources of emissions located in the Barnett Shale play in Texas. They were able to conclude two broad points: (a) even with production and processing stages factored into the lifecycle of Barnett’s Shale gas, emissions are approximately the same as conventional natural gas; again, this means that shale gas produces “less than half that typical for coal-fired” generation;
20 and (b) opportunities exist for further reducing the GHG footprint of shale gas by addressing potential sources along the life cycle where leakage can be mitigated or even entirely controlled.21
19 JISEA, Natural Gas and the Transformation of the U.S. Energy Sector: Electricity, November 2012.
20 Ibid., 4. 21 Ibid., 5.
2012 2015 2020 2035 2012-2035Federal Personal Taxes 11,384 16,564 20,811 26,676 483,860Federal Corporate Taxes 3,476 5,240 6,519 8,252 151,256Total Federal Taxes 14,860 21,804 27,330 34,928 635,116
S & L Personal Taxes 1,818 2,656 3,333 4,266 77,469S & L Corporate Taxes 9,748 14,685 18,253 23,097 423,482S & L Severance Taxes 2,487 4,199 5,688 7,276 141,469S & L Ad Valorem Taxes 1,109 1,786 2,403 2,803 57,590Total State and Local Taxes 15,162 23,326 29,676 37,441 700,011
Federal Royalty Payments 990 1,274 1,359 644 25,073Total Government Revenue 31,012 46,404 58,366 73,013 1,360,199
Lease Payments to Private Landowners 261 370 526 726 13,421
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2. Water Quality Concerns
One of the more pervasive and constant concerns regarding shale gas and the environment is the potential contamination of drinking water. After analyzing very limited publicly-available data from six plays, JISEA concluded the following: “Substantial gaps in data availability prevent a full assessment of risks to water resources resulting from shale gas operations. Only certain statistics are publicly available for each region, and in some regions that cross state boundaries, information is only available for the part of a play that is in one state.” JISEA was able to locate and analyze a relatively small amount of publicly-available data from two states that illustrates the number and relative severity of incidents regarding water contamination. Still, JISEA found that the substantial data needed to make any definitive conclusions and assessments is still lacking.22
To provide the needed data, EPA plans to release a major study of potential impacts of hydraulic fracturing on drinking water resources in late 2014. In 2009, the U.S. House of Representatives, spurred by public concern, called for EPA to research the relationship between hydraulic fracturing and drinking water resources. Research began in 2011, a progress report was released in December 2012,
23
Two notable elements of the EPA research effort are (a) its comprehensive coverage of the full, five-stage water cycle for hydraulic fracturing, and (b) the wide range of evidence to be considered when judging potential dangers to drinking water at any of these five stages. To give a sense of what happens at each stage, we have taken an EPA template and shown excerpts of EPA’s description of the five stages of the water cycle in Figure II.2.
and a final report of results is planned for late 2014.
22 Ibid., 90. 23 U.S. Environmental Protection Agency, Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources: Progress Report, December 2012.
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FIGURE II.2 Excerpts from EPA’s Description of the Five Stages
of the Water Cycle for Hydraulic Fracturing
Water Acquisition
Chemical Mixing
Well Injection
Flowback and
Produced Water
Wastewater Treatment
and Waste Disposal
Hydraulic fracturing fluids are usually water-based, with approximately 90% of the injected fluid composed of water. Estimates of water needs per well have been reported to range from 65,000 gallons for coalbed methane (CBM) production up to 13 million gallons for shale gas production…Five million gallons of water are equivalent to the water used by approximately 50,000 people for one day. (U.S. Environmental Protection Agency, Study of the Potential Impacts of Hydraulic Fracturing 14. Internal citation omitted.)
Once onsite, water is mixed with chemicals to create the hydraulic fracturing fluid that is pumped down the well.…The fluid serves two purposes: to create pressure to propagate fractures and to carry the proppant into the fracture.…Roughly 1% of water-based hydraulic fracturing fluids are composed of various chemicals…. (U.S. Environmental Protection Agency, Study of the Potential Impacts of Hydraulic Fracturing, 15.)
The hydraulic fracturing fluid is pumped down the well at pressures great enough to fracture the oil- or gas-containing rock formation… (U.S. Environmental Protection Agency, Study of the Potential Impacts of Hydraulic Fracturing, 16.)
When the injection pressure is reduced, the direction of fluid flow reverses, leading to the recovery of flowback and produced water. For this study, “flowback” is the fluid returned to the surface after hydraulic fracturing has occurred, but before the well has been placed into production…. They are collectively referred to as “hydraulic fracturing wastewater”… (U.S. Environmental Protection Agency, Study of the Potential Impacts of Hydraulic Fracturing, 18.)
Estimates of the fraction of hydraulic fracturing wastewater recovered vary by geologic formation and range from 10% to 70% of the injected hydraulic fracturing fluid. (U.S. Environmental Protection Agency, Study of the Potential Impacts of Hydraulic Fracturing, 19. Internal citation omitted.)
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As to the range of evidence, note that the one of five types of evidence is “existing data.” EPA reports that, for example, “[i]nformation on the chemicals and practices used in hydraulic fracturing has been collected from nine companies that hydraulically fractured a total of 24,925 wells between September 2009 and October 2010.”24
Water acquisition, while just one of the five stages of the hydraulic fracturing water cycle, can be an especially important step in states facing drought conditions, as is the case in some SPP states. For example, it is reported that Texas is in the midst of potentially its worst drought since the 1950s.
This would seem to be a substantial sample of real-world data that will enhance the credibility of the findings substantially. The other four types of evidence are also compelling: scenario evaluations with computer models, laboratory studies, toxicity assessments, and case studies.
25 In Oklahoma, Lake Canton was recently drained to serve water demand in Oklahoma City,26 and it is said that more than 90 percent of Oklahoma suffered “extreme” or “exceptional” drought conditions in the summer of 2012.27 While some counter those concerns by saying that the water needed for hydraulic fracturing is often less than 1 percent of a state’s total water demand,28 water scarcity issues can occur on a more localized scale. For example, water acquisition for hydraulic fracturing is reportedly as high as 47 percent of one county’s water demand in Oklahoma.29 In response to this concern, some drillers have constructively turned to recycling water used in hydraulic fracturing (i.e., using flowback water that would have otherwise been trucked away as waste)30 and using brackish water in drilling operations.31
D. To Export or Not To Export?
As already noted, the shale gas revolution has been a game-changer, in part, because it has shifted the discussion from (a) the fear that America would have to rely on LNG imports, thereby tying the price of U.S. natural gas to the world price of oil, to (b) the opportunity for America to export some of its newfound abundance of natural gas.32
24 U.S. Environmental Protection Agency, Study of the Potential Impacts of Hydraulic Fracturing, December 2012, 2.
That discussion, however,
25 Matthew Tresaugue, “Texas drought could rival state’s worst dry years,” Houston Chronicle, February 5, 2013, http://www.chron.com/. 26 Adam Mertz, “Water continues to flow out of Canton Lake,” News Channel 4, February 15, 2013, http://kfor.com/2013/02/15/water-continues-to-flow-out-of-canton-lake/. 27Mesonet, “Extreme to Exceptional Drought Covers Most of Oklahoma,” August 9, 2012, http://www.mesonet.org/index.php/news/article/extreme_to_exceptional_drought_covers_most_of_oklahoma. 28 See, e.g., Kate Galbraith, “As Fracking Increases, So Do Fears About Water Supply,” The New York Times, March 7, 2013, http://www.nytimes.com/. 29 Gayathri Vaidyanathan and Ellen Gilmer, “Water flows to money in drought-stricken drilling regions,” EnergyWire, July 30, 2012, http://www.eenews.net/public/energywire/2012/07/30/1. 30 See, e.g., Devon Energy Corporation, “Cana water reuse project helps Devon overcome drought,” accessed April 10, 2013, http://www.dvn.com/CorpResp/initiatives/Pages/CanaWaterRecycling.aspx#terms?disclaimer=yes. 31 Galbraith, “As Fracking Increases, So Do Fears About Water Supply.” 32 Some have asked why the shale gas revolution has not driven increased fracking in other countries as it has in the U.S. In Europe, it is said that there are three primary reasons why fracking activity has lagged behind. First, property rights regimes are different in Europe as compared to the U.S. In many European countries, gas deposits below the surface are considered property of the state, while in the U.S., the gas is considered property of the
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has been controversial. There is a debate on whether the federal government should enable such exports by approving the construction of liquefaction facilities.33
To provide a factual basis for that discussion, the DOE asked NERA to conduct a study on how these two opposing outcomes – the higher natural gas prices versus the higher export revenues and profits – net out.
There are those who want to keep the abundant shale gas for domestic use, saying that exports would only increase natural gas prices in the U.S. because exports increase demand. On the other side are those who say that the U.S. should not pass up the opportunity to create jobs and profits by supplying the world with natural gas produced with the innovative new drilling technologies that Americans developed.
34 NERA conducted the study using a model that incorporated both the American economy as well as global natural gas markets.35
A long list of scenarios were run in the models which reflected the uncertainty facing any forecast of future natural gas market prices such as (a) the uncertainty over the true extent of America’s shale resources and the cost of recovering them, and (b) the uncertainty around future demand for and supply of natural gas around the globe. Table II.4 is a simple excerpt from NERA’s expansive results that we want to use to address the issue of the price effects of allowing exports.
TABLE II.4 Selected Scenario Results for 2035
Source: NERA Economic Consulting, Macroeconomic Impacts, 11, Fig. 6.
Table II.4 shows the estimated wellhead price in the year 2035 under (a) three different
assumptions about the level of shale gas development in the U.S., including a Reference case plus both a High and a Low case, and (b) two different assumptions about exports: no exports
landowner. (See KPMG Global Energy Institute, Central and Eastern European Shale Gas Outlook, May 2012, 18.) Second, Europe is more densely populated, making it more difficult to find free land for drilling. (Ibid.) Third, some European countries have more strict regulations related to drilling that serve as a barrier to new fracking operations. (See, e.g., “Frack to the Future,” The Economist, February 2, 2013, http://www.economist.com/.) 33 U.S. Energy Information Administration, Effect of Increased Natural Gas Exports on Domestic Energy Markets, January 2012. 34 NERA Economic Consulting, Macroeconomic Impacts of LNG Exports from the United States. 35 Ibid., 1.
U.S. Shale Gas Development
U.S. LNG Exports (Tcf)
Wellhead Price (2010 $/Mcf)
0 $6.415.75 $7.50
0 $4.888.39 $5.97
0 $8.700.52 $8.86
Reference
High
Low
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and maximum exports (meaning exports would be at the level the world market wants to buy at the resulting market price).36
• One, as expected, exports can increase the wellhead price of American natural gas. Taking the reference case, for example, the maximum exports lead to a wellhead price in the year 2035 (in real terms) that is 17 percent higher than with zero exports – see $7.50 per Million cubic feet (Mcf) compared to $6.41 per Mcf. For the High and the Low cases, the increase in wellhead prices with maximum exports is 22 percent and 2 percent respectively.
Three important points should be made with the data in the table.
• Two, the level of exports depends importantly on the cost of producing the shale gas. For example, if the shale gas resource is consistent with the Low assumptions, the wellhead price in America is too high for any substantial export amount – exports are just 0.52 Trillion cubic feet (Tcf) so allowing exports increases the market price by only 2 percent.
• Three, assumptions about the shale gas resources dictate wellhead prices. We can see this as we look across the resources assumptions. For example, the market price with the High resource assumption and allowing maximum exports is $5.97 per Mcf. That market price is moderately lower than the price in the Reference case without exports ($6.41) and significantly lower than the price in the Low resource case without exports ($8.70).
Moving beyond the price effects, we can turn to the economic questions – that is, on net is there a positive economic impact? NERA concludes that there are always, in every scenario, “net economic benefits” with increasing LNG exports by America.37
In all of these cases, benefits that come from export expansion more than outweigh the losses from reduced capital and wage income to U.S. consumers, and hence LNG exports have net economic benefits in spite of higher domestic natural gas prices. This is exactly the outcome that economic theory describes when barriers to trade are removed.
Moreover, NERA states that this net benefit is exactly what economic theory predicts. Specifically:
38
Further, NERA describes what is being netted out as follows:
Our measure of total income is GDP measured from the income side, that is, by adding up income from labor, capital and natural resources and adjusting for taxes and transfers.
Expansion of LNG exports has two major effects on income: it raises energy costs and, in the process, depresses both real wages and the return on capital in all other industries, but it also creates two additional sources of income. First, additional income comes in the form of higher export revenues and wealth transfers from incremental LNG exports at higher prices paid by overseas purchasers. Second, U.S. households also benefit from higher natural gas resource income or rents.39
36 Ibid., 10.
37 Ibid., 1. 38 Ibid. 39 Ibid., 7.
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To put some numbers to this netting, the following chart is taken directly from NERA’s
study. For example, for the years 2015 and 2030, respectively, the chart shows, on the negative side, that “[l]abor and investment income are reduced by about $10 billion in 2015 and $45 billion in 2030.”40 On the positive side, these reductions are fully offset primarily “by increases in resource income to natural gas producers and property owners….” Gauged roughly from the chart, these positive effects appear to be about $20 billion in 2015 and $55 billion in 2030.41 Thus there are net benefits – about $10 billion in both 2015 and 2030. NERA rightly reminds us that we need to keep these estimates in perspective: “[n]ote that these are positive but, on the scale of the entire economy, very small net effects.”42
FIGURE II.3 Change in Income Components and Total GDP in USREF_SD_HR
(Billions of 2010$)
Source: NERA Economic Consulting, Macroeconomic Impacts, 8, Fig. 3.
40 Ibid., 8. 41 Ibid. 42 Ibid.
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Finally, NERA addresses what we called the “fear” that the price of natural gas in America would become linked with the highly volatile price of world oil. NERA says that does not happen in the many scenarios it analyzes. NERA states:
U.S. natural gas prices increase when the U.S. exports LNG. But the global market limits how high U.S. natural gas prices can rise under pressure of LNG exports because importers will not purchase U.S. exports if U.S. wellhead price rises above the cost of competing supplies. In particular, the U.S. natural gas price does not become linked to oil prices in any of the cases examined.43
43 Ibid., 2.
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III. EPA’s Continued Campaign on Coal (An Update) he EPA is pursuing a long list of regulations which some say constitutes a “campaign on
coal.” These regulations affect the cost of building and/or operating new and existing power plants and cover GHG emissions such as CO2, traditional air pollutants such as SO2, coal combustion residuals, and water use. EPA is pursuing these regulations using existing Clean Air Act, Clean Water Act and Resource Conservation and Recovery Act authority; that is, EPA is pursuing them without additional congressional action. For example, though many thought that federal action against GHGs was set aside when Congress did not pass a cap-and-trade bill in 2010, EPA has moved to regulate GHG emissions from stationary sources. The impetus and authority for this regulation is from the Clean Air Act, supported by the 2007 U.S. Supreme Court decision in Massachusetts v. EPA that directed EPA to consider GHGs in the context of motor vehicles. Once EPA began to regulate GHGs from motor vehicles it was obligated to begin regulation on emissions from stationary sources such as power plants. The fact that EPA’s current regulations on GHGs from power plants arrived via a court case involving motor vehicles serves to remind us that EPA, under a supportive administration, has many tools to affect the electricity industry.
This chapter discusses EPA regulations affecting coal in three parts: (a) a discussion and list of current and upcoming EPA regulations affecting the U.S. electricity industry; (b) an analysis of recent economic, policy, and regulatory developments on U.S. GHG emissions as an indicator of future GHG regulation; and (c) an example from one SPP state, Oklahoma, where a utility responded to EPA regulations by taking steps to shut down coal generation.
A. Upcoming EPA Regulations
EPA has a number of regulations that affect coal-fired electricity generation, many of which are expected to be released or revised in coming years. These regulations impact a variety of air emissions, water usage, and coal waste products. In sum, they amount to a broad
T
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campaign that will raise the costs of using traditional coal generation and, thereby, reduce its use. The regulations that have garnered the most attention recently are the MATS and the Regional Haze rule. However, there are at least 11 other EPA regulations that will affect the electricity sector. Table III.1 below describes each regulation, its current status, and gives a sense of its impact on the electricity sector.
Legal and political pushback on EPA regulations has, to date, had little effect. Although EPA has faced and will continue to face legal challenges to these regulations, recent disputes have tended to be settled in EPA’s favor. Most upcoming regulations may also be upheld under legal challenge. EPA has also faced political pressure to moderate its actions. The impact of political pressure may be less certain, but with President Obama in office until early 2017, a significant roll back in EPA’s authority in the next few years is unlikely.
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Table III.1 Boston Pacific’s List of Environmental Regulations Impacting the Electric Power Sector
NAME
DESCRIPTION
STATUS
IMPACT
AIR – GREENHOUSE GAS (GHG) EMISSIONS
GHG New Source Performance Standards (NSPS) for New Units
Restricts GHG emissions from new fossil-fuel-fired electric generating units to the emissions of natural gas combined-cycle technology (1,000 pounds of CO2 per MWh). Coal plants will need carbon capture and storage technology or the equivalent. This requirement is considered in issuing units’ preconstruction permits and is incorporated into their operating permits. These permits are generally enforced by states.
Proposed March 2012; final rule may be issued soon.
This rule would prevent new traditional coal generation from being built. According to the EPA the rule will result in only negligible costs by 2020 because market conditions are leading away from coal.
GHG New Source Performance Standards (NSPS) for Existing Units
Under Clean Air Act section 111(d), once the EPA has issued GHG regulations for new plants, it must issue guidelines for states to use in drafting plans setting standards of performance for existing fossil-fuel-fired electric generating units. The level and structure of future guidelines are unknown, but, in 2008, EPA indicated it wanted power plants to improve their operating efficiency by two to five percent.
Not yet proposed, but must be issued because of settlement agreement and Clean Air Act.
The cost of efficiency improvements is unknown. However, the EPA did state that biomass co-firing could substitute for efficiency improvements, indicating that EPA may be flexible about potential compliance methods.
GHG Prevention of Significant Deterioration (PSD) Requirements
Requires construction or operating permits for sources subject to PSD or Title V permitting anyway and that emit at least 75,000 tons per year CO2e. Also requires permits for any existing source that emits at least 100,000 tons per year CO2e and increases emissions by at least 75,000 tons per year CO2e; new sources that emit 100,000 tons per year CO2e also require permits. Implemented by states.
Currently in effect and states are issuing permits. A workgroup has been formed to discuss streamlining the permitting process.
EPA estimates that about 900 additional PSD permitting actions will be triggered each year by new and modified emission sources, including power plants. Permits may do no more than require the use of best practices.
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NAME
DESCRIPTION
STATUS
IMPACT
AIR – MULTIPLE POLLUTANT REGULATIONS
Mercury and Air Toxics Standards (MATS)
Limits emissions of mercury, other heavy metals like arsenic, and acid gases such as hydrochloric acid from new and existing coal- and oil-fired electric utility steam generating units. Compliance by existing sources is required by April 16, 2015, but state permitting authorities can provide a one-year extension. Generally implemented by states. Environmental controls must comply with the “Maximum Achievable Control Technology” requirement in the Clean Air Act.
This rule became effective April 16, 2012. The EPA then slightly modified the portion of the standard applying to new sources on March 28, 2013.
According to the EPA, MATS may cause 4.7 GW to retire by 2015, increasing average U.S. retail electricity prices by 3.1 percent in 2015. Other estimates vary: RFF estimates 4 GW of retirements and 1 percent higher average electricity prices by 2020; NERA estimated 19 to 23 GW of coal retirements through 2015.
Clean Air Interstate Rule (CAIR) / replacement rule for Cross-State Air Pollution Rule (CSAPR)
CAIR requires (and the vacated CSAPR required) certain states to limit annual SO2 and NOx emissions so downwind states can achieve the ozone and PM 2.5 NAAQS.
CSAPR, originally intended to replace CAIR, was vacated in August 2012. CAIR is temporarily reinstated until a replacement rule is issued.
The replacement rule and potential costs are unknown. However, EPA estimated that CSAPR could increase electricity rates by as much as 1.7 percent. CAIR was projected to increase electricity rates by as much as 2.7 percent.
Regional Haze rule
Limits pollutants such as NOx, SO2 and particulate matter that impair visibility in national parks and wilderness areas. The measures apply Best Available Retrofit Technology. Implemented by states.
State Implementation Plans (SIPs) were originally due to the EPA by 2007. Many were filed late. EPA was under a consent decree to approve revised SIPs or issue Federal Implementation Plans (FIPs) before the end of 2012. However, at least some remain unresolved.
EPA estimated that, assuming CAIR would be implemented, this rule would affect 491 coal units, or 218 GW, and increase national retail electricity prices by 0.1 percent on average in 2015. Some regions would experience higher costs than others.
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NAME
DESCRIPTION
STATUS
IMPACT
AIR – NATIONAL AMBIENT AIR QUALITY STANDARDS (NAAQS)
Revisions to Primary NAAQS for ozone
Limits levels of ozone in the atmosphere to protect public health. Currently set at 75 parts per billion (ppb), based on an eight-hour standard. This value is currently under review. A 2011 rulemaking postponed by President Obama had set the ozone NAAQS at 70 ppb based on the advice of the EPA’s Clean Air Scientific Advisory Committee to set the standard between 60 and 70 ppb.
Current NAAQS for ozone was announced in March 2008. EPA is projected to issue a Notice of Proposed Rulemaking on an update by early 2014. The EPA is required to review and, if appropriate, revise this standard every five years.
Based on the 2011 proposal postponed by President Obama, with a limit of 70 ppb, EPA estimated national annual costs for all affected sources in 2020 at $19 to $25 billion (2006$); if 60 ppb, $52 to $90 billion.
Revisions to Primary NAAQS for SO2
Limits the concentration of SO2 in the atmosphere to protect public health. Currently set at 75 ppb, based a one-hour standard. In 2009, the EPA’s Clean Air Scientific Advisory Committee endorsed a 1-hour standard with a range of 50 to 150 ppb. Also requires additional monitors to be installed nationwide.
This standard was set in 2010. The EPA is required to review and, if appropriate, revise this standard every five years.
EPA estimates that Electric Power Generation, Transmission, and Distribution sectors will incur annualized costs in 2020 of $699 million (2006$). New monitors could increase compliance obligation.
Revisions to Primary NAAQS for NO2
Limits the concentration of NO2 in the atmosphere to protect public health. Currently set at 100 ppb, based on a one-hour standard. This is consistent with the EPA’s Clean Air Scientific Advisory Committee’s recommendations from 2009 of 80 to 100 ppb. Also requires additional monitors to be installed.
This standard, set in 2010, is in effect but being reviewed. A NOPR is projected to be issued in January 2016. The EPA is required to review and, if appropriate, revise this standard every five years.
EPA did not estimate any costs to the electric generating unit (EGU) sector. Updated monitoring may change this conclusion. New monitors could increase compliance obligation.
Primary NAAQS for Particulate Matter (2.5)
Limits levels in air of fine particulate matter to protect public health. Current standard is an annual average of 12 micrograms per cubic meter. In 2010, the EPA’s Clean Air Scientific Advisory Committee supported a standard of between 11 and 13 micrograms per cubic meter.
Final rule announced December 2012. The EPA is required to review and, if appropriate, revise this standard every five years.
EPA did not estimate specific costs to EGUs of attaining this standard because EGUs were estimated to not have to reduce emissions beyond what was already required by MATS.
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NAME
DESCRIPTION
STATUS
IMPACT
SOLID WASTE
Coal Combustion Residuals
Will regulate the disposal of coal combustion residuals. The rule has two regulatory options. If CCRs are classified as hazardous waste, EPA will create requirements for their disposal in hazardous waste facilities. If deemed not hazardous, EPA will establish minimum national technical criteria, such as composite liner requirements, for states to include in their own regulations.
Announced May 2010; final rule projected to be issued in 2014.
EPA estimated that electricity rates could increase by 0.2 percent if CCRs were classified as non-hazardous and 0.8 percent if classified as hazardous. However, an industry estimate that examined broader “upstream” and other cost components was several times higher.
WATER
Revisions to Steam Electric Power Effluent Limitation Guidelines and Standards
Updates effluent guidelines and standards for steam electric power generating plants to limit the pollutants discharged into surface waters. Much of this pollution is from coal ash ponds and flue gas desulfurization wastes. Among the changes could be requiring waste disposal in landfills instead of surface impoundments and eliminating wastewater streams by converting waste handling systems from wet to dry handling.
In line with a consent decree, the proposed rule was issued in April 2013. A final rule is expected in 2014. This rule was last updated in 1982; EPA is required to annually review it, and revise if appropriate.
EPA says this could apply to 1,200 nuclear and fossil-fueled plants, though will cause no coal plant retirements and cost less than $1 billion annually. Affected sources will need to comply upon renewing their National Pollutant Discharge Elimination System (NPDES) permit, which lasts five years.
Cooling Water Intake Structures, CWA 316(b)
Requires existing electric generators that withdraw more than 2 million gallons of cooling water per day to limit how many fish are killed by being pinned against intake screens. New units added to existing facilities must produce results equal to at least 90 percent of closed-cycle cooling technology (i.e., cooling towers). Plants built after 2002 (“new” under this regulation) are already required to use such technology.
Proposed rule issued in Spring 2011; final rule projected for June 2013.
EPA estimated annualized costs for direct compliance by existing electric generators to be $386 million (2009$); a study commissioned by the Nat’l Association of Manufacturers estimated annualized costs of $8 billion. 559 EGUs are expected to be affected by this rule, over 45 percent of electric capacity.
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Selected Sources for Table III.1
Air – GHG Emissions: New Source Performance Standards for New Plants at http://epa.gov/carbonpollutionstandard/actions.html; Technical Support Document for the Advanced Notice of Proposed Rulemaking for Greenhouse Gases at http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2008-0318-0081; New Source Review Regulations & Standards at http://www.epa.gov/nsr/actions.html.
Air – Multiple Pollutant Regulations: MATS regulatory information at http://www.epa.gov/airquality/powerplanttoxics/actions.html and industry analyses at http://www.nera.com/nera-files/PUB_MATS_Rule_0312.pdf and http://www.rff.org/RFF/Documents/RFF-DP-12-18.pdf; Clean Air Interstate Rule information at http://www.epa.gov/cair/rule.html; Cross-State Air Pollution Rule updates at http://www.epa.gov/crossstaterule/bulletins.html; and Regional Haze rule information at http://www.epa.gov/airquality/visibility/actions.html.
Air – NAAQS: Table of NAAQS at http://epa.gov/air/criteria.html; EPA Clean Air Scientific Advisory Committee Final Reports for NAAQS at http://yosemite.epa.gov/sab/sabproduct.nsf/WebReportsbyTopicCASAC!OpenView; and Ozone NAAQS regulatory actions at http://www.epa.gov/airquality/ozonepollution/actions.html.
Solid waste: EPA’s Coal Combustion Residuals website at http://www.epa.gov/wastes/nonhaz/industrial/special/fossil/ccr-rule/index.htm; Regulatory Impact Analysis of the rule at http://www.regulations.gov/#!documentDetail;D=EPA-HQ-RCRA-2009-0640-0003; and Ballard Spahr’s summary of EPA’s intentions for this rule at http://www.ballardspahr.com/alertspublications/articles/~/media/Files/Articles/2013-01-02-EPA-Rules-for-Fossil-Fuel-Fired-Power-Plants.ashx.
Water: EPA’s Steam Electric Effluent Guidelines website at http://water.epa.gov/scitech/wastetech/guide/steam-electric/amendment.cfm. Also see EPA’s Cooling Water Intake Structures website at http://water.epa.gov/lawsregs/lawsguidance/cwa/316b/index.cfm.
Status of regulations: EPA’s Reg DaRRT website at http://yosemite.epa.gov/opei/RuleGate.nsf/content/index.html?opendocument. For EPA’s cost analysis of various regulations, see http://www.epa.gov/ttnecas1/ria.html.
Industry cost analysis: NDP Consulting’s report on the benefits and costs of EPA regulations at http://www.nam.org/~/media/423A1826BF0747258F22BB9C68E31F8F.ashx.
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B. U.S. Greenhouse Gas Emissions Profile
The direction of future policy on GHG emissions remains one of the biggest question marks confronting the electricity industry. The U.S. does not have an established national policy towards GHG emissions, but many recent environmental and energy policies from federal, state, and local governments have been undertaken with at least a partial eye towards limiting such emissions. Some examples include:
• Federal – EPA GHG New Source Performance Standards and joint rules for vehicle Corporate Average Fuel Economy and GHG emissions;
• State – RPS and energy efficiency standards; • State – The New England states’ Regional Greenhouse Gas Initiative (RGGI) cap-and-
trade program; • State – California’s cap-and-trade program. • Local – New York City’s “plaNYC” includes plans to reduce GHG emissions 30 percent
by 2030 compared to 2005 while adapting to the effects of climate change; Boulder, Colorado is exploring the establishment of municipal electric utility in large part to reduce its GHG emissions.
These existing and upcoming policies, in combination with cheap natural gas and the Great Recession apparently have already put the U.S. on path to reduce GHG emissions. Data from the EPA show that U.S. GHG emissions have declined since peaking in 2007. Whereas from 1990 to 2007, U.S. GHG emissions grew at an average annual rate of 1.0 percent, since 2007, U.S. GHG emissions have declined by an average of 2.0 percent each year through 2011. Emissions from the electricity sector grew by 1.6 percent per year from 1990 to 2007, but have since declined, on average, by 2.7 percent annually from 2007 through 2011.44
Figure III.1 below depicts this history of GHG emissions.
44 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011, April 12, 2013.
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Figure III.1 Historical U.S. Greenhouse Gas Emissions,
(Million Metric Tons CO2 Equivalent)
Source: Created by Boston Pacific based on U.S. Environmental Protection Agency,
Inventory of U.S. Greenhouse Gas Emissions and Sinks.
This new path for GHG emissions was analyzed in a recent report from the think-tank
RFF. According to RFF, even without additional legislation from Congress, the U.S. is on or near track to meet President Obama’s 2009 goal of reducing emissions 17 percent below 2005 levels by 2020.45 RFF identified expected emissions reductions from three categories that would combine to create 16.3 percent lower GHG emissions in 2020, as compared to 2005. These categories and associated reductions of GHG emissions are (a) EPA regulations (10.5 percent), (b) changes in relative fuel prices and energy efficiency (3.3 percent) and (c) state and regional cap-and-trade and RPS policies (2.5 percent).46
However, it is unclear whether such drivers will continue to produce similar reductions after 2020 absent additional federal action. If not, additional regulation or legislation may be considered if policymakers want to reach long-term goals such as the 83 percent GHG emissions reduction by 2050 envisioned in the American Clean Energy and Security Act cap-and-trade bill passed by the House of Representatives in 2009. This suggests that legislation putting a price on carbon – perhaps with an emissions tax – remains a distinct possibility over the medium- to long-term, especially if such a tax were to contribute to deficit reduction and be imposed in lieu of taxes on income.
45 Darren Samuelsohn and Lisa Friedman, “Obama Announces 2020 Emissions Target, Dec. 9 Copenhagen Visit,” The New York Times, November 25, 2009, http://www.nytimes.com/. 46 Dallas Burtraw and Matt Woerman, US Status on Climate Change Mitigation, Resources for the Future, October 2012, 9-10. A similar paper from WRI also suggests that states, regional organizations, and the federal executive branch have enough methods to reduce GHG emissions that the U.S. may hit this target without any further action from Congress.
0
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C. A Relevant Example
An example of one utility’s ongoing response to new EPA regulations affecting coal generation may give a sense of the types of decisions being made “on the ground.” The following example is of an SPP-area utility, PSO and its response to two EPA regulations currently affecting coal generation: the MATS and the Regional Haze rule.
The MATS and Regional Haze regulations primarily affect coal plants. MATS sets numerical limits for the emissions of heavy metals and acid gases from new and existing coal and oil units.47 Existing plants are required to comply with MATS by April 16, 2016.48 EPA’s Regional Haze rule limits visibility impacts from NOx, SO2, and particulate matter in national parks and wilderness areas. The final rule was issued in 1999 but the process of each state creating State Implementation Plans (SIPs) has been ongoing. The haze control plans are to be updated every 10 years, on path to meet a goal of natural background conditions by 2064.49
Oklahoma submitted a Regional Haze SIP to EPA for approval on February 19, 2010. This SIP set specific, modest emissions controls for every major source of NOx and SO2 emissions in Oklahoma, including PSO’s Northeastern plant, which contains two coal units. EPA approved some of Oklahoma’s SIP but disapproved certain portions referring to SO2 controls. EPA then issued a Federal Implementation Plan (FIP) with its alternative plan for controlling SO2 emissions in Oklahoma. The FIP for the Northeastern coal units would have required PSO to install flue-gas desulfurization (FGD) units, or “scrubbers.”
50
Instead of complying with the FIP, PSO decided to negotiate a settlement with EPA to amend its Regional Haze obligations.
It was to go into effect five years after being approved.
51
47 U.S. Environmental Protection Agency, Fact Sheet: Mercury and Air Toxics Standards for Power Plants, U.S. EPA website, last modified December 21, 2011,
The resulting settlement is a compliance agreement between PSO, the EPA, the Sierra Club, and the Oklahoma Department of Environmental Quality. It requires PSO to take three main actions: (1) retire one Northeastern coal unit in 2016; (2) retrofit the other Northeastern coal unit with (a) a dry-sorbent injection system (instead of FGD), (b) an activated carbon injection system, and (c) a fabric filter baghouse in 2016; and (3) shut down the retrofitted Northeastern coal unit by 2026. Total lifetime SO2 emissions under this
http://www.epa.gov/mats/pdfs/20111221MATSsummaryfs.pdf. 48 The 2016 date assumes that a utility asked its state permitting authority for and was granted one additional year for compliance, as envisioned by the MATS regulation. If not, the compliance date is April 16, 2015. For facilities that are needed for reliability purposes and that cannot otherwise meet the 2016 deadline, EPA will consider granting additional time to comply. 49 U.S. Environmental Protection Agency, “Regional Haze: Timeline for States to Implement EPA’s Rule,” EPA website, accessed April 19, 2013, http://www.epa.gov/ttn/oarpg/t1/fr_notices/implemnt.pdf. and U.S. Environmental Protection Agency, “Regional Haze-VISTAS,” EPA website, accessed April 19, 2013, http://www.epa.gov/region4/air/modeling/regional_haze.html. 50 Approval and Promulgation of Implementation Plans; Oklahoma; Federal Implementation Plan for Interstate Transport of Pollution Affecting Visibility and Best Available Retrofit Technology Determinations, Final Rule, 76 Fed. Reg. 81728, 81729 (December 28, 2011). 51 Note that other utilities are responding to RH and MATS differently. For example, Oklahoma Gas & Electric challenged the FIP in court, hoping to get it overturned; some utilities are installing updated emissions control equipment; some, like PSO, are settling; others are retiring coal units altogether.
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settlement would be roughly equal to SO2 emissions had both units operated through their expected lifespans with FGD units.
Because PSO is planning to retire coal capacity in 2016, it also issued an RFP for baseload generation to replace the retiring capacity. This RFP was conducted throughout summer 2012. The winning bidder was Calpine Corporation, offering a 15-year power purchase agreement (PPA) for a share of Calpine’s Oneta Energy Center natural gas combined-cycle plant.
A ruling on cost recovery for all of these compliance actions is now pending before the Oklahoma Corporation Commission.
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IV. Developments Driving the Future of Transmission Planning
ne of the most important roles SPP (and its board) play is that of planning the expansion of the transmission grid. Indeed, FERC included transmission expansion planning as one of its eight essential functions of an RTO,52 finding
that “the RTO must have ultimate responsibility for both transmission planning and expansion within its region that will enable it to provide efficient, reliable and non-discriminatory service…”53 Looking forward, SPP’s role in transmission planning and expansion is only expected to intensify in importance. Transmission investment across the U.S. is expected to grow. For example, The Brattle Group estimates that the industry will invest approximately $96 to $128 billion in new transmission assets in the eight-year period from 2012 to 2020.54 To put that estimate in context, investor-owned utilities’ actual transmission investments over the 14-year period from 1995 to 2009 totaled less than $80 billion, according to the Brattle Group.55
52 Regional Transmission Organizations, Order No. 2000, 18 CFR Part 35 (December 20, 1999), FERC Stats. & Regs. 89 FERC ¶ 61,285 (1999)
http://www.ferc.gov/legal/maj-ord-reg/land-docs/RM99-2A.pdf, (hereinafter “Order No. 2000”). 53 Order No. 2000, 485. 54 WIRES and The Brattle Group, Employment and Economic Benefits of Transmission Infrastructure Investment in the U.S. and Canada, May 2011, http://www.brattle.com/_documents/UploadLibrary/Upload947.pdf. 55 Ibid., 3-4. Numbers are estimated from Figure 2 and are in 2011$.
O
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SPP and the board have developed and approved SPP’s 2012 transmission expansion plans, which include $1.5 billion in approved transmission investment for the Integrated Transmission Plan 10-year Assessment portfolio.56
In preparing this report, we looked around for factors that may drive this important transmission planning and expansion function in the future and selected five drivers for discussion. Two immediate, direct drivers of the future of transmission planning and expansion that are relevant today and will remain relevant for the foreseeable future are (a) FERC’s Order No. 1000, and (b) closer scrutiny of the costs and benefits of transmission expansion by end users and regulators. Three more indirect drivers that may have some impact on future transmission planning and expansion efforts include (c) a potential breakthrough in HVDC technology, (d) the increased importance and integration of cybersecurity, and (e) integration of distributed generation. We summarize each below.
A. FERC Order No. 1000
The first direct, immediate development that has and will continue to impact the future of transmission planning and expansion is FERC’s Order No. 1000.57 Although issued in July 2011, the effects of FERC’s Order No. 1000, the agency’s latest policy directive related to transmission access, are only beginning to take shape. Order No. 1000 requires transmission plans to incorporate public policy benefits, develop cost allocation procedures, remove the incumbent transmission owners’ “right of first refusal” in building new projects, and conduct interregional transmission planning and cost allocation.58
Order No. 1000’s directive to remove the right of first refusal from open access transmission tariffs appears to be an important event in the evolution of transmission development. Specifically, this requirement obligates transmission providers (like SPP) to allow any entity – including those who do not already own transmission in a region – to propose a transmission project for consideration in a regional transmission planning process, have that project selected for inclusion in the plan, and recover costs of the project from customers in that region pursuant to the terms of the regional tariff, all without the threat of the incumbent utility exercising its right of first refusal to build the project on its own.
We will focus on the latter two requirements here.
We see this development as a significant step forward in the development of competition in the transmission side of the electricity business. We see Order No. 1000 as removing one barrier to competition for non-incumbent transmission owners. It will encourage more robust competition in expanding the transmission grid going forward which should lead to more efficient, less costly outcomes for end users. We think Order No. 1000 could be the beginning of competitive reform in the transmission business. That is, it brings early-stage reform similar to
56 Southwest Power Pool, 2013 SPP Transmission Expansion Plan Report, January 29, 2013, 12, http://www.spp.org/publications/2013STEPReport.pdf/. 57 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, 76 Fed. Reg. 49842 (August 11, 2011) 136 FERC Stats. & Regs. ¶ 61,051, July 21, 2011, http://www.ferc.gov/whats-new/comm-meet/2011/072111/E-6.pdf, (hereinafter “Order No. 1000”). 58 Ibid., 2, 12, 56-7, 63-4.
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that brought to the generation side of the business by Congress and FERC through vehicles like the Public Utility Regulatory Policies Act of 1978, which allowed entry by qualifying facilities.
However, the true impact of FERC’s Order No. 1000 in opening the transmission side of the business to competition may be determined by the states, not at the federal level. In the wake of the Order No. 1000 process, several states have passed (or are considering passing) new legislation that will create an in-state right of first refusal for incumbent transmission owners. North Dakota,59 South Dakota,60 and Minnesota61 have each passed laws introducing a right of first refusal for incumbent transmission owners. In the SPP states, Nebraska is considering a bill introduced on February 1, 2013, that would create an in-state right of first refusal for Nebraska’s incumbent transmission owners.62 The New Mexico House of Representatives recently passed a similar bill,63 and that measure is now being considered in the New Mexico Senate.64 And, Arkansas found a merchant transmission developer’s request for certification to build a multi-state transmission project through Arkansas’ borders unwarranted.65
FERC itself has deferred to state or local regulations that implement a right of first refusal. In Order No. 1000, FERC stated that “nothing in [Order No. 1000] is intended to limit, preempt, or otherwise affect state or local laws or regulations with respect to construction of transmission facilities, including but not limited to authority over siting or permitting of transmission facilities.”
66
Another highlight in FERC’s Order No. 1000 is the requirement of transmission providers to engage in transmission planning with their neighbors, so-called “interregional transmission planning.” This means that neighboring control areas will be required to plan multi-state, multi-jurisdiction transmission projects more efficiently, and to have a cost-sharing mechanism in place to get the projects funded. SPP already conducts coordinated transmission planning with its neighbors. For example, its Joint Operating Agreement with the Midwest ISO has had joint planning procedures in place since 2004. Nevertheless, SPP must still make a showing to FERC regarding its planning procedures with neighboring control areas to cure itself
As a result, the actual impact of FERC’s implicit competitive reforms regarding the right of first refusal will be significantly influenced by the state.
59 Sixty-Third Legislative Assembly of North Dakota, S. 2322, (January 8, 2013), http://legis.nd.gov/assembly/62-2011/session-laws/documents/PUTIL.PDF?20130422071703. 60 Eighty-Sixth Session Legislative Assembly of South Dakota, S. 132, (2011), http://legis.state.sd.us/sessions/2011/Bills/SB132ENR.pdf. 61 Minnesota Department of Commerce, Report to the Minnesota Legislature on Minnesota’s Electric Transmission System – Now and Into the Future, Division of Energy Resources, in Consultation with the Minnesota Public Utilities Commission, January 15, 2013, 8, http://mn.gov/commerce/energy/images/Electric_Transmission_Jan2013.pdf. 62 One-Hundred-Third Legislature of Nebraska, First Session, LB 388, http://nebraskalegislature.gov/FloorDocs/Current/PDF/Intro/LB388.pdf. 63 Fifty-First Legislature of New Mexico, First Session, “Final Passage,” March 14, 2013, http://www.nmlegis.gov/Sessions/13%20regular/votes/HB0163HVOTE.pdf. 64 Fifty-First Legislature of New Mexico, First Session, S. 175, (2013), http://www.nmlegis.gov/Sessions/13%20Regular/bills/senate/SB0175.pdf. 65 “In the Matter of the Application of Plains and Eastern Clean Line LLC for a Certificate of Public Convenience and Necessity to Construct, Own and Operate as an Electric Transmission Public Utility in the State of Arkansas,” Arkansas Public Service Commission, Docket No. 10-041-U, Order No. 9, (January 11, 2011). 66 Order No. 1000, pp 227.
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of its obligation under Order No. 1000. SPP is underway in those efforts, but the details of that coordination remain in development and it is expected that SPP will make few, if any, changes to its current coordination efforts with neighboring control areas.
For SPP, coordinated interregional planning may be especially important over the long term with one of its neighbors in particular. The Midwest ISO already shares a large common border with SPP. That border will soon grow substantially when Entergy joins the Midwest ISO, making Midwest ISO SPP’s largest and most impactful neighbor. The map of each control area is shown below in Figure IV.1.
Figure IV.1
Map of Midwest ISO, Entergy, and SPP Footprints
Source: Citizens League “Electrical Energy: Affordability and Competitive Pricing Working Team,” (Powerpoint presentation), http://www.citizing.org/data/projects/working-team-affordabilitycompetitive-pricing/MISO%20Issues.ppt.
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As the map demonstrates, SPP’s transmission system has an extensive border with Entergy and now the Midwest ISO. As a result, SPP anticipates additional loop flow on its system once Entergy completes its integration with Midwest ISO. Indeed, loop flow concerns have been the focus of multiple regulatory proceedings at the federal and state levels in the past two years.67
Loop flow can create incentive for transmission solutions, some of which could be multi-regional, as well as generation solutions that could reduce any additional realized loop flow from Entergy’s integration with Midwest ISO.
B. Scrutiny of the Costs and Benefits of Transmission Expansion
A second direct potential driver in the future of transmission planning is an increased level of scrutiny on the costs and benefits of transmission expansion project costs. Specifically, going forward, we could see potential for increased consumer backlash for the costs of transmission expansion projects, especially when the economic, reliability, or public policy benefits of those projects are questioned.
While we have not seen widespread scrutiny or backlash of this nature, there is one recent anecdotal instance that illustrates our point. It involves Interstate Power and Light Company (IPL), a Midwestern utility that filed a complaint at FERC alleging that it has paid $170.5 million in transmission expansion costs to connect wind power to the grid from which it has received no commensurate benefits. IPL, which serves 500,000 customers in Iowa and Minnesota, claims that the Midwest ISO Tariff,68 which sets out the rules for passing through transmission expansion costs to transmission customers like IPL, also creates “aberrant economic incentives” for generators to site their projects at locations that minimize their development costs without regard to the least cost solution with respect to the overall transmission system. IPL argues that most of the transmission expansion costs borne by IPL to date have involved network upgrades designed for the specific purpose of facilitating generator interconnections. IPL claims that it does not use the energy from the wind generators that have interconnected to the grid through these transmission expansions, and that IPL has not experienced any material improvements to reliability or enjoyed lower energy prices as a result of these upgrades for which IPL has had to pay. ITC Midwest, LLC, in a response to IPL’s complaint, disagrees with IPL, claiming that the transmission projects for which IPL has paid provide reliability benefits, economic benefits, (even if the interconnecting generators have purchased power agreements with utilities in another state), and environmental benefits.69
The IPL case is a direct challenge by a transmission customer to a FERC-approved method for allocating the costs of transmission expansion in an organized market – in this case,
67 “In the Matter of a Show Cause Order Directed to Entergy Arkansas, Inc. Regarding its Continued Membership in the Current Entergy System Agreement, or any Successor Agreement Thereto, and Regarding the Future Operation and Control of its Transmission Assets,” Arkansas Public Service Commission, Order No. 54, Docket No. 10-011-U, issued October 28, 2011. See also Midwest Independent Transmission System Operator, 136 FERC ¶ 61,010 (2011). 68 IPL’s Complaint names ITC Midwest, LLC as the sole defendant in the proceeding. This is because IPL is a customers of ITC Midwest, LLC, which passes on transmission expansion costs it is charged under the Midwest ISO Tariff to its customers, including IPL. 69 ITC Midwest, LLC’s Answer to IPL’s Complaint, Docket No. EL12-104-000 (October 4, 2012), 5, 21.
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Midwest ISO. IPL asks FERC to set for hearing the relevant tariff provisions that require IPL to pay for these projects without receiving commensurate benefits, and to order refunds for unjust and unreasonable charges to IPL to date. FERC has yet to act on the complaint, which was filed in September 2012. When it does, FERC will likely provide some insight into its position on measuring economic, reliability, and environmental benefits purported by transmission expansion projects. If granted, IPL’s complaint could become a precedent and template for other utilities to use to challenge their transmission expansion bills at FERC.
C. A Potential Breakthrough in HVDC Technology
Next, we turn to three more indirect developments that could potentially drive the future of transmission planning and expansions. The first of these is a recently claimed breakthrough in HVDC technology that could have a significant impact in the future structure of the grid.
One of the limitations of HVDC is the physical challenge of switching – turning on and off – HVDC, which, if possible, would allow more control of power flow and thus could potentially increase the number of connection points on a HVDC line. Currently, HVDC use is based on single point-to-point connections of generation and load. Recently, Switzerland-based company, ABB, announced that it has developed a HVDC circuit breaker that, if commercialized, could allow for increased integration of HVDC transmission into existing AC grids or even build-outs of HVDC grids.70 We note that Siemens and Alstom are also competing with ABB to commercialize a HVDC circuit breaker.71
Circuit breakers are a type of power system protection equipment that are used in substations and distribution stations to detect and isolate faults so they do not propagate to other parts of the system. This has allowed the delivery of power to be controlled and managed in our networked AC grids. Until recently, there have not been any applications that could break a HVDC current efficiently and reliably. One of the difficulties in breaking a HVDC current is the continual flow of high magnitude current. ABB claims to have solved this problem with their HVDC circuit breaker.
Integration of HVDC into AC grids requires the use of converter stations, which convert AC into DC and vice-versa. Converter stations are a significant cost component of a HVDC transmission system, and normally two converter stations are required for a single line. The Western Electricity Coordinating Council (WECC) developed assumptions for transmission line and equipment costs with the assistance of Black & Veatch for its transmission planning process. WECC’s assumed costs for a 500kV HVDC converter station with a capacity rating of 3,000 MW is $445 million or about $148/kW.72
70 Michael Kavanagh, “ABB hails ‘supergrids’ breakthrough,” The Financial Times, November 7, 2012,
Commercialization of HVDC circuit breakers could lead to a reduced need for converter stations because HVDC circuit breakers would allow
http://www.ft.com/cms/s/0/721f02e0-2834-11e2-afd2-00144feabdc0.html#axzz2QxcCSxIk. 71 Ibid. 72 Black & Veatch, Capital Costs for Transmission and Substations, Recommendations for WECC Transmission Expansion Planning, October, 2012, sec. 3-6, http://www.wecc.biz/committees/BOD/TEPPC/TAS/121012/Lists/Minutes/1/121005_TransCapCostReport_finaldraft.pdf.
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multiple entry or exit points, where power could be taken on or off the DC lines, thereby making HVDC integration more cost effective.73
It is not clear how far away we are from commercializing HVDC circuit breakers, but the impact of such development could be far reaching. Transmission planning processes, including SPP’s, should be flexible enough to accommodate the growth of HVDC projects if commercialization of a HVDC circuit breaker is achieved.
D. Cybersecurity
Another development that may indirectly impact the future of transmission planning is the growing importance of cybersecurity for critical electricity infrastructure assets. Cybersecurity is increasingly important for both utility-owned systems and third-party systems that interact with the grid.74
Cyber attacks in the U.S. have increased recently. There has been a 17-fold increase in cyber attacks on U.S. infrastructure between 2009 and 2011, according to General Keith B. Alexander, head of the National Security Agency and the U.S. Cyber Command. There are concerns over the level of U.S. preparedness to handle these attacks; General Alexander gave the U.S. preparedness for a large-scale cyber attack “about a 3” out of 10.
Any point where the grid is connected to the wider world is a potential cybersecurity vulnerability. Cybersecurity policy must work to reduce the likelihood of successful cyber attacks, and, because threats will never be eliminated 100 percent, it must also reduce the likely damage from cyber attacks by ensuring one compromised system cannot shut down the entire grid.
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Traditional cyber attacks on electric systems may break into utility systems to steal confidential customer or operational data or prevent networked systems from functioning by overwhelming them with requests for communication (a “denial of service” attack). However, in addition to impacting virtual systems and networks, cyber attacks can target key physical grid and generator equipment. A 2007 report by the National Research Council of the National Academies (which was only declassified in 2012) described the potential damage:
If they could gain access, hackers could manipulate SCADA systems to disrupt the flow of electricity, transmit erroneous signals to operators, block the flow of vital information, or disable protective systems. Cyber attacks are unlikely to cause extended outages, but if well coordinated they could magnify the damage of a physical attack. For example, a cascading outage would be aggravated if
73 C.M. Franck, “HVDC Circuit Breakers: A Review Identifying Future Research Needs,” IEEE Transactions on Power Delivery 26, no. 2 (2011): 2, http://www.future-energy.ethz.ch/uploads/tx_ethpublications/Franck_2011_HVDC_CB_review_IEEE_Trans_PowDel.pdf. 74 Miles Keogh and Christina Cody, Cybersecurity for State Regulators 2.0: With Sample Questions for Regulators to Ask Utilities, NARUC Grants & Research, February 2013, http://www.smartgridlegalnews.com/NARUC%2520Cybersecurity%2520Primer%25202.0.pdf. 75 David E. Sanger and Eric Schmitt, "Rise Is Seen In Cyberattacks Targeting U.S. Infrastructure,” The New York Times, July 26, 2012, http://www.nytimes.com/.
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operators did not get the information to learn that it had started, or if protective devices were disabled.76
Recent events have also shown that key electric power systems equipment is at risk from cyber attacks. As described in the February 2013 NARUC Cybersecurity Primer 2.0, in 2006, the Idaho National Laboratory staged an attack – codenamed “Aurora,” – on a replica of a power plant’s control system. The attack misused safety systems to send the generator out of control, physically disabling it. The NARUC Primer also discusses how, in 2009, a specially designed software worm called “Stuxnet” infected control systems of centrifuges in Iran, physically damaging them. Undoubtedly, SCADA and other key electric power systems face risks.
77
Pre-existing efforts within the electricity sector, such as NERC’s recently approved fifth set of standards,
78 put the sector in a good place to face recent increased policy around cybersecurity standards. On February 12, 2013, President Obama signed an executive order on cybersecurity and a Presidential Policy Directive on infrastructure security.79 The executive order increases information sharing between the government and private sector as well as throughout the government. It also directs the National Institute of Standards and Technology to develop a framework to reduce the risk to national infrastructure.80 As some legal experts suggest, there is a chance that this framework could conflict with established NERC frameworks. Utilities and other key players in the electricity sector should stay abreast of its development and provide expert input where appropriate.81
Though the electricity sector has relatively well-established cybersecurity standards, the NARUC Cybersecurity Primer makes the case that setting and following standards is unlikely to provide sufficient protection. The process of setting standards is slow compared to the pace of technological change. As a result, cybersecurity standards should be viewed as a minimum level of compliance. The focus should be on active risk management, rather than a check-the-box approach. The NARUC Primer describes the difference between compliance with standards and effective cybersecurity:
Additionally, those who argue that the [NERC] standards are incomplete point out that compliance only proves compliance; utilities’ cybersecurity should be based in risk management. Risk management includes assessment, mitigation and continuous improvement, whereas compliance offers a view of cybersecurity at a fixed point in time, not a dynamic picture of it. Utilities may be compliant to the [NERC] standards and still not be secure. Utilities may also be secure but not be
76 National Research Council of the National Academies, Terrorism and the Electric Power Delivery System, (Washington, DC: The National Academies Press, 2012), 2. 77 Keogh and Cody, Cybersecurity for State Regulators 2.0, 7. 78 NERC “Reliability Standards,” North American Electric Reliability Corporation website, accessed April 16, 2013, http://www.nerc.com/page.php?cid=2%7C20. 79 Exec. Order No. 13636, 78 Fed. Reg. 11739 (February 19, 2013). 80 U.S. Department of Homeland Security, Fact Sheet: Executive Order on Cybersecurity/ Presidential Policy Directive on Critical Infrastructure Security and Resilience, February 13, 2012, http://www.dhs.gov/news/2013/02/13/fact-sheet-executive-order-cybersecurity-presidential-policy-directive-critical/. 81 Andrew Art, Jonathan Simon and Michael O’Neill, “ Obama Administration Moves Forward on Cybersecurity,” Van Ness Feldman, last modified February 20, 2013, http://www.vnf.com/news-alerts-808.html.
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compliant to the [NERC] standards. One is not the guarantee of the other.82
(emphasis in original)
E. Integration of Distributed Generation
The final potential driver we discuss is an expanded role for distributed generation, a topic covered in more depth in chapters VII and VIII herein. Transmission providers typically allow distributed generation to compete alongside other generation and demand-side resources in serving as alternatives to transmission solutions. For example, in PJM, distributed generation,83 by participating as a capacity resource through PJM’s demand response program, can be an alternative to the need for transmission upgrades. PJM’s Regional Transmission Expansion Plan (RTEP) allows demand response, including on-site generation which clears in PJM’s capacity market auctions, to be included in the assumptions for RTEP development and physically modeled in the baseline power flows. As such, demand response and on-site generation can mitigate or delay the need for transmission upgrades.84 In addition, in developing its RTEP, PJM conducts sensitivity studies and scenario analysis that accounts for potential changes in expected future system conditions in order to mitigate the possibility that transmission projects be either inappropriately included or excluded from the transmission plan. In doing so, PJM identifies, evaluates, and analyzes potential transmission expansions and enhancements, demand response programs (including on-site generation), and other alternative technologies as appropriate to maintain system reliability.85
Another example comes from the Pacific Northwest, where the utility PacifiCorp allows distributed generation to compete on an even footing against other generation, demand-side, and transmission solutions. PacifiCorp’s Integrated Resource Plan (IRP) considers a number of generation, distributed generation, demand-side management, and transmission options to ensure that an optimal combination of resources is utilized to cost-effectively meet its customers’ demands for electricity. For example, as noted in chapter VI, a wide range of distributed generation resources were identified among other supply-side resources as candidate resources for the optimal portfolio of resources. In addition, a large transmission expansion project, the Energy Gateway, was identified as a requirement to meet its customers’ needs. Multiple scenarios of the Energy Gateway design and build-out were selected and modeled. PacifiCorp
Finally, in developing its plan for economic transmission projects to include in the RTEP, PJM must also analyze and provide the level and type of new generation and demand response (including on-site generation) that could eliminate the need for the enhancement or expansion.
82 Keogh and Cody, “Cybersecurity for State Regulators 2.0,” 9. 83 PJM does not use the term “distributed generation.” Instead, PJM uses the term “On-Site Generator” to refer to generation facilities, including behind-the-meter generation, that are (i) not capacity resources, (ii) are not injecting into the grid, (iii) are either synchronized or non-synchronized to the Transmission System, and (iv) can be used to reduce demand for the purpose of participating in the PJM Interchange Energy Market. 84 PJM Interconnection, L.L.C., PJM Manual 14B: PJM Regional Transmission Planning Process: Revision 23, March 1, 2013, Sec. 2.4, 31, http://pjm.com/~/media/documents/%20manuals/m14b.ashx. 85 PJM Interconnection, L.L.C., PJM Operating Agreement, April 12, 2013, Schedule 6, http://www.pjm.com/~/media/documents/agreements/oa.ashx.
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used Ventyx’s System Optimizer capacity expansion tool, which can solve simultaneously for resources and transmission expansion to find the optimal combination under a number of RPS and CO2/gas price assumptions. In addition, PacifiCorp uses their Planning and Risk model to model stochastic risk such as in loads, market prices, gas prices, hydro availability, and forced outages.
Like PJM and PacifiCorp, SPP also has a process in place to account for all resources, including demand-side resources, such as distributed generation, in its transmission and resource planning processes. As a result, any increase in distributed generation can be reflected and considered by SPP in its current processes and expansion models.
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V. The Future of U.S. Electricity Bills: Flat Demand, Rising Rates?
new topic for this year’s Annual Looking Forward Report is the potential for increases in the electricity bills for ratepayers. Our discussion in this chapter does two things. First, we provide data that shows that, on average, ratepayers
have enjoyed almost flat electricity bills in recent years and we note some anecdotal factors that have helped to keep bills from rising. Second, we explain that the conditions of recent years may be changing and could produce cost increases that could drive electricity bills higher, even if demand for electricity stays flat. Our purpose is not to forecast future retail rates, nor model the impacts of changes in natural gas prices or electricity demand on average U.S. electricity bills; our purpose is only to present the idea that increases in electricity bills could be on the horizon. We use a report from Deloitte and other anecdotal data and credible forecasts of key variables that often impact electricity rates as support.
Since 2007, as shown in Figure V.1, the EIA reports that the average U.S. monthly residential electricity bill has been almost flat.86
86 U.S. Energy Information Administration, “Electric Sales, Revenue, and Average Price,” U.S. EIA website, last modified September 27, 2012,
http://www.eia.gov/electricity/sales_revenue_price/. This data was converted to
A
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Figure V.1 Average U.S. Residential Monthly Bill (2011$)
Source: U.S. Energy Information Administration, “Electric Sales, Revenue, and Average Price.”
Electricity bills have enjoyed favorable conditions during this period. The Great
Recession, which began in 2007, has helped keep demand for electricity down.87 The shale gas revolution, as explained in chapter II herein, has cut domestic natural gas prices significantly. Capital expenditures by utilities have been helped by historically low interest rates88 and by public subsidies. For example, the American Recovery and Reinvestment Act of 2009 set aside more than $42 billion for energy projects89 while the Production Tax Credit has subsidized renewable generation with $7.9 billion (in 2010$) from 1992 to 2010, and an additional $1.1 billion in 2011 just for wind generation.90
2011$ for this report. To arrive at the U.S. Average Residential Monthly Bill data in each year, EIA aggregated residential revenue and customer data from Form 861, then divided the revenue by the number of customers, divided again by 12 (for 12 months) and multiplied by 1000 (because the revenue was in thousands of dollars).
87 Southern Company, “Electricity Demand and the Great Recession,” (presented at Georgia State University Economic Forecasting Conference, November 17, 2010), accessed April 17, 2013, http://www.rdhawan.com/Robinson/Conf_Nov10/Kenneth_Shiver_presentation.pdf. See also: Eileen O’Grady, “Sluggish electric demand plagues U.S. utilities,” Reuters, May 11, 2012, http://www.reuters.com/. 88 “Six years of low interest rates in search of some growth,” The Economist, April 6, 2013, http://www.economist.com/. 89 Fred Sissine, et al., Energy Provisions in the American Recovery and Reinvestment Act of 2009, Congressional Research Service, March 3, 2009, 1-2, https://opencrs.com/document/R40412/2009-03-03/download/1005/. 90 Molly Sherlock, “Impact of Tax Policies on the Commercial Application of Renewable Energy Technology,” (statement before the House Committee on Science, Space, and Technology Subcommittee on Investigations and Oversight & Subcommittee on Energy and Environment, April 19, 2012), 3,
$80.00
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2007 2008 2009 2010 2011
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Going forward, as the conditions for these variables become potentially less favorable, could we be headed for a period of noticeable increases for U.S. electricity customers’ monthly bills? To answer that question, we looked to credible forecasts of these variables that historically have driven U.S. electricity rates. In addition, we reviewed a 2012 report by the Deloitte Center for Energy Solutions91
which provided an analysis of the future of the U.S. electric power industry, including expected electricity rates going forward. We found that U.S. utilities have significant capital expenditure requirements in the near term, and that forecasts by EIA, the Brattle Group, and others suggest that conditions for variables – like natural gas prices – will likely not remain as favorable as they have been in recent times. And while forecasts by these groups suggest that U.S. electricity demand will stay relatively flat, or even decrease in some cases, conditions appear ripe for a period of increasing retail electricity bills for U.S. end users.
A. U.S. Demand for Electricity
The Deloitte report suggests that there is a “potential for slow, stagnant, or even declining electricity consumption.”92 Deloitte claims that EIA, in its 2012 Energy Outlook, assumes an annual growth in electricity consumption of just 0.73 percent to 2020.93 In addition, Deloitte summarizes a report by The Brattle Group, stating that “factors such as increased energy efficiency, new smart grid technologies and structural changes in the economy will cause electricity demand and consumption in 2020 to decline by 7.5 to 15 percent and 5 to 15 percent, respectively, as compared to what they would have been without efficiencies.”94
There are likely to be several factors that will impact U.S. electricity demand going forward, according to Deloitte. A rebounding U.S. economy could help drive demand for electricity higher, although Deloitte claims that “there has been some level of ‘permanent demand destruction’ as a result of the recession.”
95 Deloitte notes that “[n]ew sources of demand for electricity” could push overall U.S. demand higher, such as (a) “increased electronics in the home,” (b) “new computer server farms,” (c) “growth in demand for electric vehicles,” (d) “incremental water resources management requirements,” including desalination, irrigation, and water treatment, and (e) a “potential resurgence of the U.S. manufacturing base as a result of the competitive advantage created by low [domestic] natural gas prices . . . associated with shale gas.”96 Despite these potential sources of new demand, Deloitte also notes that technological advances in energy efficiency will allow customers to “do the same with less.”97
http://science.house.gov/hearing/subcommittee-investigation-and-oversight-subcommittee-energy-and-environment-%E2%80%93-joint-hearing
. 91 Deloitte, The Math Does Not Lie: Factoring the future of the U.S. electric power industry, Deloitte Center for Energy Solutions, October 22, 2012. 92 Deloitte, The Math Does Not Lie, 1. 93 U.S. Energy Information Administration, Electricity Supply, Disposition, Prices, and Emissions, Reference case Table, Annual Energy Outlook 2012, http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2012&subject=6-AEO2012&table=8-AEO2012®ion=0-0&cases=ref2012-d020112c, cited in Deloitte, The Math Does Not Lie, 1. 94 Ahmad Faruqui, Ph.D. and Doug Mitarotonda, Ph.D., Energy Efficiency and Demand Response in 2020, The Brattle Group, November 2011, cited in Deloitte, The Math Does Not Lie, 1. 95 Deloitte, The Math Does Not Lie, 7. 96 Ibid. 97 Ibid.
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In addition, studies by Deloitte provide evidence that “changing electric customer trends” will “challenge conventional wisdom about the level of demand growth, if any, for the foreseeable future.” In Deloitte’s reSources 2012 Study,98 which polled individual households, Deloitte found that: (a) 83 percent of consumers in Deloitte’s 2012 survey “reported [that] they took steps to reduce their electricity consumption – up from 68 percent in the 2011 Study;” and (b) interest in smart energy technologies is “noticeably growing,” especially with “younger adults” who are “clearly more receptive to making the investment.”99 In addition, Deloitte’s reSources 2012 Study polled businesses and found that: (a) “90 percent of U.S. businesses have set goals focused on managing electricity usage;” (b) of those businesses, “85 percent cite reducing electricity costs as essential to staying competitive – up from 76 percent in 2011;” (c) the average target for reduction in electricity consumption among businesses is a reduction of 23 percent over a 3.5 year period; and (d) “35 percent of businesses report some level of self-generation of electricity with another 17 percent planning to do so in the future.”100
B. Natural Gas Prices
As the marginal fuel for electricity generation in many areas in the U.S., natural gas prices can be a significant driver of electricity prices. As noted above, the shale gas revolution has had a game-changing impact on recent and current prices. However, there is growing evidence that natural gas prices may face upward pressure over the coming period. In its 2012 Annual Energy Outlook, as seen in Figure V.2, EIA forecasts natural gas prices to increase steadily through 2035 in all five scenarios it modeled, varying factors such as economic growth and the anticipated total production from shale gas wells.
98 Deloitte, Deloitte reSources 2012 Study: Insights into Corporate Energy Management Trends, Deloitte Center for Energy Solutions, May 2012 and Deloitte, Deloitte reSources 2012 Study: Insights into Emerging Trends of Energy Customers, Deloitte Center for Energy Solutions, May 2012. 99 Deloitte, The Math Does Not Lie, 7. 100 Deloitte, The Math Does Not Lie, 8.
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Figure V.2 EIA Natural Gas Price Forecast
Source: U.S. Energy Information Administration, Annual Energy Outlook 2012, 92.
While forecasts are uncertain and limited in their reliability, there is intuitive evidence
favoring an increase in natural gas prices over the near term. First, as Deloitte points out, “it is generally agreed that prices must rise to at least $4.50 per MMBtu in order to make the production of much of the U.S. shale gas resources economically feasible.”101
We report such a near-term increase in chapter II based on NYMEX futures. Additionally, the prospect of new environmental regulations for horizontal drilling and fracturing to extract shale gas could add new compliance costs to domestic shale gas drillers, helping to drive domestic gas prices higher. Finally, the potential for U.S. natural gas exports could also help increase domestic natural gas prices, as we explained more fully in chapter II.
C. Interest Rates
Interest rates, as noted above, remain “extraordinarily low,”102 but must, according to Deloitte, “necessarily rise in the foreseeable future. The questions are only when and how much.”103 Financial houses, like Goldman Sachs, have also predicted a near-term rise in interest rates.104
101 Deloitte, The Math Does Not Lie, 6 (citation omitted).
Higher interest rates mean that debt financing for utility capital expenditure will become more expensive, helping to ultimately push retail rates higher.
102 Ibid., 5. 103 Ibid. 104 Jan Harvey, “Goldman Sachs predicts turn in gold bull cycle,” Reuters, December 6, 2012, http://in.reuters.com/.
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D. Utility Capital Expenditures: Upgrading the Grid
Higher interest rates are especially relevant given the projections for increased capital expenditures needed to update the current, aging grid. Deloitte explains that utilities now face “an unprecedented increase in capital spending to address [the] aging [U.S.] infrastructure.”105
Regarding new generation, Deloitte estimates that the utility industry will invest over $150 billion in new generation capacity between 2012 and 2020.
That increased capital expenditure will likely fall into three categories of investment: new generation, new transmission, and new distribution.
106 New transmission asset investment will total between $96 and $128 billion over that same time period, according to The Brattle Group.107 IHS Emerging Energy Research echoes The Brattle Group’s estimates, projecting that total transmission investment from 2011 to 2020 will be approximately $102.5 billion.108 Regarding distribution investment, Deloitte estimates that utilities will need to make “substantial” investments in the distribution system “not only to meet ever-changing residential, commercial and industrial infrastructure requirements but also as a result of smart meter investments by the majority of the electric distribution sector.”109 Deloitte estimates that “[s]mart meter deployments from mid-2012 through the end of 2015 . . . could cost approximately $4.4 to $11.6 billion.”110
E. Utility Capital Expenditures: Environmental Compliance Costs
Additional capital expenditures will also be needed to comply with existing and expected environmental regulations imposed on U.S. utilities. The EPA, for example, estimates that the annual incremental cost of its MATS rule will be $7.4 to $9.4 billion per year between 2015 and 2030.111
Other environmental regulations can also impose significant compliance costs on U.S. utilities. For example, EPA’s proposed Thermal Power Plant Cooling Water Intake Structures rule is projected to cost utilities between $290 million and $4.7 billion annually.
112
105 Deloitte, The Math Does Not Lie, 1.
The EPA’s
106 Ibid., 4. 107 WIRES and The Brattle Group, Employment and Economic Benefits of Transmission Infrastructure Investment in the U.S. and Canada, May 2011, http://www.brattle.com/_documents/UploadLibrary/Upload947.pdf/. 108 IHS Global Pressroom, “Investment in U.S. High-Voltage Transmission to Top $41 Billion Over the Next Decade, press release, December 1, 2011, http://www.emerging-energy.com/content/press-details/Investment-in-US-High-Voltage-Transmission-to-Top-41-Billion-Over-the-Next-Decade/37.aspx. The $102.5 billion is derived from IHS’s estimate that the U.S. is expected to see $41 billion invested in high-voltage transmission over the next ten years and that high-voltage transmission investment will be about 40 percent of total U.S. transmission investment during this time. 109 Deloitte, The Math Does Not Lie, 4. 110 Ibid. 111 Ibid. 112 Paul J. Miller, A Primer on Pending Environmental Regulations and their Potential Impacts on Electric System Reliability, Northeast States for Coordinated Air Use Management, January 2013, 15. Note that in Table III.1
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proposed Coal Combustion Residuals rule is projected to cost between $587 million and $1.5 billion annually.113
On top of direct environmental compliance costs, U.S. utilities also must bear the cost of increasing state RPS, which often require purchases of relatively expensive generation for public policy reasons. As Deloitte points out, “there is little debate that renewables (i.e., wind and solar) are not cost competitive today with more traditional generation sources, and that the vast majority of renewables in service or under construction are the result of tax incentives or [RPS].”
While uncertain at this time, any new legislation or regulations involving GHG emissions could impose significant costs on utilities, and, ultimately, end users.
114 Even with recent levels of renewable energy in the U.S. that help meet RPS standards in 29 states plus DC and RPS “voluntary goals” in seven others, the U.S. Partnership for Renewable Energy Finance estimates that 3.62 GW of additional annual renewable energy capacity will be needed to meet all RPS targets between 2012 and 2020.115
The rate impact of these expenditures will be exacerbated if public subsidies supporting renewable energy dry up and the true cost of these initiatives reaches U.S. end users’ monthly electricity bills.
F. Pension Obligations
Another potential driver of future U.S. electricity rates is found on the balance sheets of the utilities themselves. Like other companies, utilities often have future obligations to pay pensions and benefits to current employees once they retire. Typically, U.S. utilities recover costs of paying pension obligations to their employees through rate base.116 Thus, if a U.S. utility has underfunded pension liabilities, it can seek rate increases related to paying out pension obligations as they come due.117
The likelihood that some major U.S. utilities will need to ask for rate increases to cover maturing pension obligations is significant. Many major U.S. utilities have pension obligations that exceed the fair value of the pension assets by a significant margin. Table V.1 shows that of the 10 utilities with the largest pension obligations in the industry, nine – listed in Table V.1 – were underfunded as of 2011.
118
Recovery of those pension obligations will only serve to increase U.S. electricity bills for end users.
within chapter III above, we cite the annualized cost of this rule as $386 million; this represents EPA’s estimate of the costs utilities will incur under EPA’s preferred regulatory option at a seven percent discount rate. 113 U.S. Environmental Protection Agency, “Frequent Questions: Coal Combustion Residues (CCR) – Proposed Rule,” U.S. EPA website, last modified November 15, 2012, http://www.epa.gov/wastes/nonhaz/industrial/special/fossil/ccr-rule/ccrfaq.htm#20. 114 Deloitte, The Math Does Not Lie, 5. 115 U.S. Partnership for Renewable Energy Finance, Ramping Up Renewables: Leveraging State RPS Programs amid Uncertain Federal Support, June 2012, 17. 116 Russ Choma, “Pension Liabilities Loom: Industry Slow to Confront Problem.” EnergyBiz, November/December 2012, 19. 117 Ibid. 118 Ibid., 16.
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Table V.1 U.S. Utilities with Underfunded Pension Obligations
Source: Russ Choma, “Pension Liabilities Loom,” 16.
In sum, these changing conditions and the need for increased spending could produce higher average monthly electricity bills, on average, for U.S. residential customers, even if the customer’s demand remains flat. Worsening conditions – such as increases in interest rates and rising natural gas prices – could presage higher monthly bills as utilities pass these higher costs on to their customers.
Utility 2011 Underfunded StatusPG&E $3.007 billionExelon $2.236 billionConsolidated Edison $4.025 billionPPL $1.197 billionSouthern Company $1.279 billionFirstEnergy $2.110 billionAES $1.671 billionEntergy $1.788 billionAmerican Electric Power $688 million
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VI. Electric Vehicles (Update)
s an update to last year’s Annual Looking Forward Report, anecdotal evidence continues to suggest slower than expected EV sales. As a result, the Obama administration is backing off from its goal of 1 million EVs by 2015.119 Sales
data also shows that EVs remain on the periphery in the U.S. automobile market with sales accounting for less than one-half of 1 percent of total automobile sales.120 According to the Electric Drive Transportation Association, in 2012, total plug-in sales were 52,835 compared to total vehicle sales of 14,439,684. We note that our usage of the term “EV” or “electric vehicle” refers to a vehicle that has the capability to recharge its batteries via the electric grid. Thus, hybrid vehicles, such as the Toyota Prius, are not included in the EV classification. Even if hybrid vehicles were lumped together with EVs, combined sales in 2012 were 487,480, representing only 3.4 percent of total vehicle sales.121
119 Ayesha Rascoe and Deepa Seetharaman, “U.S. Backs Off Goal Of One Million Electric Cars By 2015,” Reuters. January 31, 2013,
Since EVs’ introduction in 2010 in the U.S., only about 80,000 have been sold. For perspective, in the 2011 Annual Looking Forward Report, it was projected that SPP’s share of total EVs would only be 3 percent by the time 1 million EVs were on the road, resulting in a very small increase in system load. The potential for a demand shock appears even less likely today.
http://www.reuters.com/. 120 Electric Drive Transportation Association, “Electric drive vehicle sales figures (U.S. Market)-EV Sales,” EDTA website, accessed April 19, 2013, http://www.electricdrive.org/index.php?ht=d/sp/i/20952/pid/20952. 121 Ibid.
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In last year’s Annual Looking Forward Report, one of our conclusions on the prospects for EVs was that their life-cycle cost may become competitive with conventional vehicles, especially if government subsidies are included. We note, however, that the federal tax credit of up to $7,500 for the purchase of new EVs is set to phase out once a manufacturer sells its first 200,000 EVs.122 For example, if Nissan sells its 200,000th Leaf, then the tax credit will phase out for any future EV produced by Nissan. The loss of the tax credit would make it a challenge for EVs to compete, even if prices decline over time.123
In addition, other issues that we identified last year, such as “range anxiety” and a lack of infrastructure are hurdles that still remain. We point out that The New York Times recently generated controversy when one of its reporters test drove a Tesla EV and became stranded due to the EV underperforming its estimated range.
The Congressional Budget Office (CBO) published a report on the effects of federal tax credits on the purchase of EVs. In the report, the CBO indicates that by 2020, EV prices would have to come down by 40 percent from levels in 2011 with the full amount of the existing tax credit in order to be cost competitive with conventional vehicles.
124
Competition from natural gas vehicles (NGVs) is another challenge to EV market penetration. There appears to be some momentum in both government and industry to develop NGVs. Last year, we mentioned that Chrysler and GM were planning to build trucks that could run on compressed natural gas and gasoline. In March of this year, the Obama administration released a fact sheet of President Obama’s blueprint for a clean and secure energy future.
Regardless of what actually transpired, the bottom line is that the public’s perception of EV range limitations (as well as the reality) must be changed in order for large-scale adoption to occur.
125 The fact sheet includes proposals to fund research on advanced vehicle technologies, including vehicles running on domestically-produced natural gas, and to provide incentives for medium- and heavy-duty trucks that run on natural gas. States have already been active in promoting NGVs, with Oklahoma and Texas both purchasing NGVs for their government fleets.126,127
While EVs may not be making much headway in the U.S., their future may rest with China, which is making an aggressive push to become a leader in EVs. The Chinese government issues a strategic plan every five years to, among other things, set certain economic development objectives. The latest five-year plan, for 2011 to 2015, identifies clean energy vehicles as one of seven priority industries.
128
122 Internal Revenue Service, “Qualified Vehicles Acquired after 12-31-2009.” IRS website, last modified April 8, 2013,
China is focusing on EVs for a number of widely varied reasons: (a) to ‘leapfrog’ foreign rivals in the automobile market, (b) to reduce the country’s dependency on
http://www.irs.gov/Businesses/Qualified-Vehicles-Acquired-after-12-31-2009. 123 U.S. Congressional Budget Office, Effects of Federal Tax Credits for the Purchase of Electric Vehicles, September 2012, 9. 124 John M. Broder, “Stalled on Tesla’s Electric Highway,” The New York Times, February 8, 2013, http://www.nytimes.com/. 125 Office of the Press Secretary, “FACT SHEET: President Obama’s Blueprint for a Clean and Secure Energy Future, the White House website, last modified March 15, 2013. 126 Matthew I. Slavin, Ph.D., Where Can I Fill Up: A Survey of Private and Public Sector Actions to Provide New Fueling Facilities For Natural Gas Vehicles, American Clean Skies Foundation, August 2012, 41-43. 127 Oklahoma Department of Central Services, “Awarded Vehicles by State,” Ok.gov Solicitations Public Search attachment, accessed April 8, 2013, https://www.ok.gov/dcs/solicit/app/solicitationDetail.php?conID=410. 128 KPMG China, China’s 12th Five-Year Plan: Overview, March 2011, 2.
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foreign oil, and (c) to reduce pollution, including CO2 emissions.129 China’s promotion of EVs is more ambitious than U.S. efforts. For example, China is targeting 5 million EVs by 2020130 and in some cases is offering a subsidy for EVs that is equivalent to around $19,000, which is more than double the tax credit offered in the U.S.131 In addition, Chinese companies have been eager to acquire financially unsuccessful U.S. EV and battery businesses.132 Notably, two of these businesses, EV manufacturer Fisker Automotive, Inc. and battery maker A123 Systems, had been recipients of a loan and grant, respectively, from the DOE. A123 Systems was purchased by Chinese firm Wanxiang Group Inc. However, we note that negotiations with Fisker Automotive, Inc. and Chinese automakers, Zhejiang Geely Holding Group and Dongfeng Motor Group Co. have stalled.133
If China is the most hopeful market for EVs, the near-term future of the industry may not be bright. That is because even with an aggressive agenda to lead the global EV industry, sales have not taken off in China. For example, a McKinsey study on EVs in China states that in 2011, automakers only produced 6,000 EVs with only 1,000 EVs registered in the third quarter of 2011, accounting for less than 0.02 percent of total vehicle registrations during that same period.
134 Furthermore, the study also indicates that the deployment of charging apparatus has been slow with two major Chinese electric power entities having built only 16,000 charging piles in 2011; this is especially low given a government target of 400,000 by 2015. We note that China faces some of the same problems that have hampered EV penetration in the U.S. However, unlike the U.S., China does have additional, compelling factors like the severe, well-publicized pollution episodes that may give greater incentive for EVs to gain traction there. It has been reported that globally, one-third of polluting emissions is attributed to transportation, but in Beijing, half of harmful emissions is caused by transportation.135
As we have seen with solar photovoltaic (PV) modules, China strategically targeted that industry years ago, and as a result, has been able to develop a manufacturing base and supply chain to allow them to leapfrog countries that have had long established technology footholds. China also has made EVs a strategic objective as part of their effort to fix their pollution problem, but also as a means to gain a substantial share of world auto sales. If there is potential for an eventual electricity demand shock in the U.S. from EVs, it is possible that it might start with cheaper EV imports from China.
129 McKinsey & Company, Recharging China’s Electric Vehicle Aspirations, China Auto Hub, April 2012. 130 Colum Murphy, “In China, Older Cars Clog the Air,” The Wall Street Journal, January 14, 2013, http://online.wsj.com/. Note that, in comparison to the U.S. automobile market, China has less than half the number of cars on the road than the U.S., only 92.7 million compared with about 247 million. 131 Joanne Chiu and Colum Murphy, “China’s BYD Looks to Triple Sales of Electric Vehicles,” The Wall Street Journal, February 24, 2013, http://online.wsj.com/. 132 Ibid. 133 Emily Glazer, Sharon Terlep and Mike Ramsey, “Fisker Hires Advisors as Loan Looms,” The Wall Street Journal, March 8, 2013, http://online.wsj.com/. 134 McKinsey & Company, Recharging China’s Electric Vehicle Aspirations. 135 Murphy, “In China, Older Cars Clog the Air.”
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VII. Distributed Generation as a Component of Demand Response
emand response in SPP is expected to grow steadily over the next 10 years. However, not all demand response is the same. For example, some demand response responds to price signals, while other demand response is called upon
in times of reliability emergencies. Demand response varies by technology, too. Some demand response is actually generation – called “distributed” generation – which refers to “relatively small-scale generators that produce several kilowatts . . . to tens of megawatts . . . of power and are generally connected to the grid at the distribution or substation levels.”136 It is important to note that the vast majority of SPP’s demand response is distributed generation, which it defines as generation that is connected on the load side of the meter.137 Specifically, SPP recently reported that 1,410 MW of its approximately 1,444 MW of demand response is distributed generation.138
136 MIT, The Future of the Electric Grid: An Interdisciplinary MIT Study, December 5, 2011, 109. “[D]istributed generation is distinct from dispersed generation, which is not connected to the grid.” Ibid.
That means that approximately 98 percent of SPP’s current demand response is coming from distributed generation.
137 SPP refers to distributed generation as “Behind the Meter Generation” in its Tariff. See Southwest Power Pool, Open Access Transmission Tariff, Sixth Revised Volume No. 1, May 16, 2012, Attachment AE, sec 1.1, Definitions B. 138 SPP’s Filing in FERC Docket No. ER12-550-001, December 17, 2012, 15.
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Distributed generation varies in its technology, too, and, therefore, in its reliability and environmental performance; keep in mind that distributed generation ranges from diesel engines to solar roof panels. As SPP realizes an increase in demand response participation, the board should seek more granular statistics on technology and performance so as to be best informed in making policy decisions.
We first pointed out that demand response was expected to grow in the coming years in the 2011 Annual Looking Forward Report, noting the impact of the Integrated Marketplace launch on opportunities for demand-side participation at the wholesale level.139 In its most recent long-term reliability assessment, NERC projects significant growth in demand response in SPP. Specifically, NERC sees an increase in total SPP demand response of 59.2 percent between 2013 and 2022, growing to 2,408 MW in total.140 As a result, demand response resources will be the equivalent of about 4 percent of total internal demand in 2022.141
In short, demand response in SPP is here to stay. The board has already dealt with regulatory requirements by FERC to create opportunities for demand response to participate in SPP’s wholesale markets through SPP’s compliance filings
142 with FERC Order No. 719.143 So, too, the board has addressed the requirement to pay demand response resources a “just and reasonable rate” through SPP’s compliance filing144 with FERC Order No. 745.145 More demand response-related actions may be required going forward, and if that is the case, the board should be aware that not all demand response is the same. Take PJM as an example. In PJM, demand response can be “economic” – i.e., responsive to price signals – or “emergency,” meaning responsive to reliability events. Economic demand response can provide energy only via voluntary load reductions. Emergency demand response can provide energy and/or capacity through mandatory reductions, competing on an equal footing alongside traditional generation resources. Distributed generation is a type of demand response which can provide either economic or emergency demand response.146
In this year’s report, we take a deeper look at distributed generation as a component of demand response. Distributed generation typically refers to generation that is located at or near the point of use, but is used to reduce load in wholesale markets. Typically, distributed generation is connected to the distribution grid or directly to customer load and does not require use of the transmission network. Distributed generation provides “demand response” by turning on at the direction of the transmission operator and reducing wholesale load. For example, if
139 Craig R. Roach, Ph.D., Stuart Rein, Vincent Musco, Sam Choi and Andrew Gisselquist, Southwest Power Pool Annual Looking Forward Report, Boston Pacific Company, Inc., April 15, 2011, 37-41. 140 North American Electric Reliability Corporation, 2012 Long-Term Reliability Assessment, November 2012, 235. 141 Ibid. 142 SPP’s Filing in FERC Docket No. ER12-550-001. 143 Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, III FERC Stats. & Regs., Regs. Preambles ¶ 31,281 (2008), as amended, 126 FERC ¶ 61,261, order on reh’g, Order No. 719-A, III FERC Stats. & Regs., Regs. Preambles ¶ 31,292, reh’g denied, Order No. 719-B, 129 FERC ¶ 61,252 (2009). 144 See SPP’s Filing in FERC Docket No. ER11-4105-000, July 22, 2011. 145 Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, 134 FERC ¶ 61,187 (2011) and Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745-A, 137 FERC ¶ 61,215 (2011). 146 PJM, “PJM Load Management,” (Powerpoint presentation at PJM State & Member Training, January 2012), http://www.pjm.com/Globals/Training/Courses/~/media/660355C146E74AABBFCD4D811A0567EE.ashx.
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Utility A has 100 MW of load and provides 5 MW of demand response via a distributed generation resource, it can provide “demand response” by reducing its wholesale load to 95 MW and using its 5 MW distributed generation to meet the remaining 5 MW of load.
As already noted, not all distributed generation is created equal. Distributed generation can include “a wide range of generation technologies, including gas turbines, diesel engines, solar photovoltaics, . . . wind turbines, fuel cells, biomass, . . . small hydroelectric generators,” and combined heat-and-power units, which “are capable of providing heat for buildings or industrial processes using [waste] energy from electricity generation.”147
Like traditional generation, distributed generation’s reliability varies with its technology. Just like traditional generation, fossil fuel-fired distributed generation provides more reliable performance than renewable fuel distributed generation. A recent study on the impact of distributed generation on the transmission grid concluded that distributed generation’s impact on the reliability of the transmission grid is related to the reliability of the distributed generation itself. Intermittent distributed resources (e.g., solar and wind) can negatively impact reliability of the grid, according to the study, which stated:
. . . [D]istributed generation in general improves the [transmission] system characteristics if the distributed generation is reliable. However in the more common case in which the distributed generation has more variability, the system can become significantly less robust with the risk of a large blackouts becoming larger…It is clear that distributed generation can have a number of impacts, positive and negative, on the system robustness coming from both the reliability of the generation (wind/solar etc) which both stresses the system and changes the actual generation capacity and from the fraction which is distributed which make the system less stressed. These results suggest that when planning for the incorporation of variable distributed generation into the transmission grid, careful analysis of the impact of the variable component on the nominal generation margin is essential [sic].148
In addition, like traditional generation, distributed generation differs in environmental performance across the range of technologies. Renewable distributed generation has little or no emissions compared to fossil-fired distributed generation, like diesel engines. However, because the EPA wanted to accommodate distributed generation as a demand response resource, it granted a limited exemption from its emissions requirements for diesel engine distributed generation for up to 100 hours per year, as long as that distributed generation is participating in an emergency demand response program and certain reliability thresholds have been triggered.
149
147 MIT, The Future of the Electric Grid, 109.
The EPA explained that the 100-hour exemption will help backup diesel engines to run long
148 D.E. Newman et al., The Impact of Distributed Generation on Power Transmission Grid Dynamics¸ IEEE, (Paper presented at the 44th Hawaii International Conference on System Sciences, Kauai, Hawaii, January 2011). 149 “EPA releases final rule on diesel engines used in emergency DR,” Restructuring Today, January 16, 2013. See also U.S. Environmental Protection Agency, Fact Sheet: Final Amendments to the Emission Standards for Reciprocating Internal Combustion Engines, U.S. EPA website, last modified January 15, 2013, http://www.epa.gov/ttn/atw/rice/20130114emergencyfs.pdf.
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enough in one year to meet the requirements in ISO tariffs for emergency demand response programs.150
Despite these differences, RTO markets, including SPP, allow all types of distributed generation to participate in their markets as demand response resources. However, not all U.S. jurisdictions classify distributed generation as a part of demand response. For example, PacifiCorp, a major utility that serves several states in the Pacific Northwest, identifies distributed generation as a distinct resource option in its integrated resource planning. In its IRP, PacifiCorp classifies distributed generation as a supply side resource as opposed to a demand side resource.
151 These identified distributed generation resources are small generators with capacities ranging from 10 kW to 3.78 MW.152
Going forward, as demand response in SPP grows, the board may benefit from probing the details of the demand-side resources coming online. As we explained above, not all demand response is created equal. More granular data will provide the board with a better understanding of the demand-side resources being attracted to participate in its markets, and improve efforts by SPP and its stakeholders to attract new investment in demand response and distributed generation consistent with SPP’s overall cost, reliability, and environmental objectives.
150 “EPA releases final rule on diesel engines used in emergency DR,” Restructuring Today, January 16, 2013. 151 PacifiCorp, 2011 Integrated Resource Plan. 152 Ibid., 122.
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VIII. Other Strategic Issues of Note
he closing chapter of this year’s Annual Looking Forward Report looks briefly at three other strategic issues for the board’s consideration. The first is legislative and regulatory in nature, related to the impact of the Dodd-Frank legislation and
recent CFTC regulations on the electricity industry. Thanks to broad language in Dodd-Frank, traditional electricity products – from spot energy to financial transmission rights – have been swept up in regulations related to financial derivative products. The second issue considers the future of the nuclear power industry, both in the U.S. and abroad. Domestically, we see some early-stage evidence of movement on the modular nuclear investment front, with two recent DOE-funded projects moving forward. Abroad, we see China (and others) leading the way in new nuclear development to meet demand and to combat health-threatening environmental conditions; it appears that China has brushed aside post-Fukushima safety fears. Third, we look more speculatively at three factors driving the U.S. toward a less-centralized electric grid. We explain how cybersecurity costs and fears, weather-related damage and outages, and rising retail rates can all create incentives for a less-centralized electric grid.
T
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A. Dodd-Frank
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), signed into law in July 2011, expanded the authority of the Commodity Futures Trading Commission (CFTC) to include regulation of “swaps,” which were defined so broadly as to potentially include RTO-market transactions, including energy, capacity, ancillary services, and financial transmission rights.153 While the CFTC’s Final Rule on its newfound jurisdiction in July 2012 exempted peaking-supply contracts, full requirements contracts, and other electricity-related products that involved physical delivery, it chose not to address RTO-related products.154 Instead, the CFTC stated that it would consider exemptions on a case-by-case basis under the standards and procedures specified in the Dodd-Frank Act for a public interest waiver.155
Later, in August 2012, the CFTC issued a proposed final order relating to a joint petition filed by six U.S. ISOs (California ISO, ISO-NE, PJM, Midwest ISO, ERCOT, and NYISO). The proposed final order would grant ISOs exemptions, subject to certain conditions, related to the major RTO products: (a) day-ahead and real-time energy (including virtual transactions); (b) financial transmission rights; (c) forward capacity; and (d) ancillary services.
156 These proposed directives were made final in an order issued on March 28, 2013.157 SPP, as a RTO, will be subject to CFTC’s rules and will potentially need to make amendments to its tariff to comply, as some ISOs, like California ISO, have already begun to do.158
This will be especially important for SPP as the Integrated Marketplace introduces financial transmission rights and other products covered by CFTC’s Orders.
B. Future of Nuclear Power (An Update)
As we mentioned in last year’s Annual Looking Forward Report, in the U.S. small modular reactors (SMRs) have been getting more attention given the headwinds for large-scale nuclear power development. In fact, recently the federal government announced that it will help fund the commercialization of a 180-megawatt SMR in Oak Ridge, Tennessee with a goal of obtaining a license from the Nuclear Regulatory Commission by 2022.159
153 Akin Gump Strauss Hauer & Feld LLP, “CFTC Rule Provides Dodd-Frank Exclusions for Energy Companies,” July 17, 2012,
The U.S. DOE Office of Nuclear Energy’s Small Modular Reactor Licensing Technical Support program anticipates spending up to $452 million in its effort to support SMR technology. This push to go smaller is spurred by several factors, including the view that modularity would allow the manufacture of key components in a factory environment, siting flexibility, and lower capital investment. The first recipient of federal funding for the development of SMR technology is a partnership, called Generation mPower LLC, between Babcock & Wilcox (B&W) and Bechtel. Generation mPower LLC will lead the effort to construct the first SMR in the U.S. with B&W providing the
http://www.akingump.com/en/news-publications/cftc-rule-provides-dodd-frank-exclusions-for-energy-companies.html. 154 Ibid. 155 Ibid. 156 Clearing Exemption for Swaps Between Certain Affiliated Entities, 77 FR 50425 (August 21, 2012). 157 Clearing Exemption for Swaps Between Certain Affiliated Entities, 17 CFR Part 50 (April 1, 2013), http://www.cftc.gov/ucm/groups/public/@newsroom/documents/file/federalregister040113.pdf. 158 See California ISO Filing in FERC Docket No. ER13-404-000, November 16, 2012. 159 Ryan Tracy, “Nuclear Power’s New Hope: Small Reactors,” The Wall Street Journal, November 22, 2012.
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reactor design and technology and Bechtel providing engineering, procurement, and construction services. We note that B&W already has a prototype facility and is in the first phase of testing. The commercial project will be built on a site owned by Tennessee Valley Authority, which plans to apply for a license and to operate the reactors. A main driver in developing SMR technology is the cost; at around $5,000/kW, B&W believes that SMR is the affordable approach to nuclear power.160
However, the future of nuclear generation is likely to be driven by countries outside the U.S. This is true for both (a) new nuclear generation, the majority and most innovative of which is being constructed in developing countries with quickly growing electricity demand, and (b) the existing nuclear generation fleet, the fate of which is being decided in developed countries such as Germany and Japan, which are considering retiring some or all of their nuclear generation.
If commercialization of SMR technology is successful, it may spark a revival of nuclear power development in the U.S.
New nuclear generation is currently being driven by increasing electricity demand in developing countries. The World Nuclear Association, a global nuclear industry group whose members control nearly 90 percent of world nuclear generation, states that “[o]ver 60 power reactors are currently being constructed in 13 countries plus Taiwan… notably China, South Korea and Russia.” Further, an additional 160 power reactors with a net capacity of 177,000 MW are in the planning stage with even more proposed.161
• China will be a major force in the future of nuclear power, with 15 plants in operation, 26 plants under construction, and a goal to quadruple its nuclear capacity by 2020.
The following brief discussions of nuclear generation developments in China, South Korea and Russia give a sense of the scale of developments occurring in those countries.
162 These plants under construction include the world’s first Westinghouse AP1000 reactor; this reactor is the first of the Generation III+ reactors to receive design certification from the U.S. Nuclear Regulatory Commission.163
• South Korea plans to bring nine reactors online by 2021, adding a total of more than 12 GW of new capacity. All but one of these new reactors will be South Korea’s version of the Advanced Pressurized Water Reactor based on the U.S. Generation III reactor design. Generation III reactors have been in operation since first being installed in Japan in 1996.
164
• Russia is currently building 10 reactors, with more planned. With planned construction more than offsetting retiring plants, Russia’s nuclear generating capacity is set to rise by 50 percent by 2020, or by about 12 GW. Russia is also a leader in the fast neutron cycle, which promises more efficient use of uranium and is the
160 Matthew L. Wald, “Deal Advances Development of a Smaller Nuclear Reactor,” The New York Times, February 20, 2013. 161 World Nuclear Association, “Plans for New Reactors Worldwide,” World Nuclear Association website, last modified March 2013, http://www.world-nuclear.org/info/Current-and-Future-Generation/Plans-For-New-Reactors-Worldwide/. 162 Ibid. 163 Westinghouse, “AP1000,” Westinghouse Nuclear website, accessed April 18, 2013, http://www.ap1000.westinghousenuclear.com/. 164 World Nuclear Association, “Advanced Nuclear Power Reactors” World Nuclear Association website, last modified March 19, 2013, http://www.world-nuclear.org/info/Nuclear-Fuel-Cycle/Power-Reactors/Advanced-Nuclear-Power-Reactors/#.UTu7ndbkvlc.
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technology used in four of the six next generation (Generation IV) nuclear reactors being developed internationally for deployment in the 2020 to 2030 timeframe.165 Russia also is developing smaller floating reactors to use in remote locations.166
For the existing global nuclear fleet, the biggest challenge is safety concerns. Specifically, existing fleets in Germany and Japan have been targeted for shutdown in the aftermath of the Fukushima nuclear accident in March 2011.
Russia’s most recent Federal Target Program envisions a 25-30 percent nuclear share of electrical generation by 2030, 45-50 percent by 2050 and 70-80 percent by the end of the century.
167 In Germany, support for nuclear power has shifted back and forth in recent years. Germany has 17 nuclear power reactors, totaling more than 20 GW of capacity, which supplied one-quarter of Germany’s electricity in 2010. In 2000, Germany passed a law beginning the phase-out of nuclear energy. Political power shifted in 2009, and the nuclear reactor lifetimes were extended. However, in March, 2011, after the Fukushima nuclear disaster, Germany immediately closed the oldest eight reactors and decided to phase out and close all other nuclear reactors by 2022. This capacity will be replaced by a mix of coal- and gas-fired plants and renewables.168
In Japan, the Fukushima accident shifted the future of nuclear generation from bright to murky. Through early 2011, nuclear generation was Japan’s biggest source of electricity capacity, producing as much as 30 percent of Japan’s electricity from 50 reactors. Japan also had plans to significantly increase the long-term role of nuclear power generation to both reduce energy imports and help address climate change. This significant role for nuclear energy was in place despite the country’s understandably difficult relationship with nuclear power due to its status as the only country to have suffered an attack from a nuclear weapon. However, when the tsunami hit in March 2011 and caused massive devastation and the accident at the Fukushima nuclear plant, concerns over nuclear safety led to the shutdown of all but two of Japan’s nuclear reactors. A poll taken in June 2012 indicated that 74 percent of respondents agreed that Japan should gradually decommission its entire nuclear fleet.
169 To complicate matters, the recently re-elected Prime Minister Shinzo Abe now says he plans to restart reactors that pass safety tests, and that the zero nuclear goal of his political opposition was unrealistic.170
165 World Nuclear Association, “Fast Neutron Reactors,” World Nuclear Association website, last modified March 15, 2013, http://www.world-nuclear.org/info/Current-and-Future-Generation/Fast-Neutron-Reactors/#.UTu44tbkvlc. 166 World Nuclear Association, “Nuclear Power in Russia,” World Nuclear Association. website, last modified April 2013, http://www.world-nuclear.org/info/Country-Profiles/Countries-O-S/Russia--Nuclear-Power/#.UTu4u9bkvlc. 167 Specific plants in the U.S. have also been the subject of security concerns recently as well, including the San Onofre plant in California and Oyster Creek in New Jersey. 168 World Nuclear Association, “Nuclear Power in Germany,” World Nuclear Association website, last modified April 2013, http://www.world-nuclear.org/info/Country-Profiles/Countries-G-N/Germany/#.UT3ThNbkvlc. 169 Kazuaki Nagata, “Fukushima Meltdowns Set Nuclear Energy Debate on its Ear: Second of five parts,” The Japan Times, January 3, 2012, http://www.japantimes.co.jp/. 170 “ABE: Japan’s Nuclear Reactors Might Be Restarted,” The Tokyo Times, December 2012, http://www.tokyotimes.com/.
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C. Drivers Toward a Less-Centralized Grid
The idea of a decentralized grid – one in which power is not generated from a central point and distributed outward, but, rather, generated close to points of use – is not new. And while we are not suggesting any sort of sudden, large-scale adoption of a decentralized grid, three current issues could create some incentive for a less-centralized system, as each addresses particular risks or costs associated with today’s centralization: (a) cybersecurity, (b) severe weather, and (c) rising retail rates for homes and businesses.
One driver of a less-centralized system may be increased concerns about cybersecurity, as discussed in chapter IV. The threat of cyber attacks may foster a desire for alternatives to relying solely on the bulk transmission grid because cyber attacks increase the risk of major, cascading outages like the one that occurred in the August 2003 blackout. To minimize the risk from any one attack or outage, each region of the grid may be made more autonomous with “smart grid” technology; this could increase the use of local generation. However, the two-way communication technology that enables a more autonomous and less-centralized grid also creates new access points for cyber attacks, potentially increasing the number of attacks. Transmission planners will need to monitor their rollout of smart grid technology and related cybersecurity measures to ensure that if smart grid technologies increase the number of attacks, they also decrease the impact from each attack enough to reduce the overall threat to the grid.
Advances in microgrids may be another driver of a less-centralized system. From recent hurricanes to major snowstorms, we have seen how vulnerable our centralized electrical system is to extreme weather events. Residences and businesses can be out of power for many days. With a majority of power lines being above ground, it is easy to see some of the weaknesses in our power grid. In addition, as mentioned above, the interconnectedness of our grid makes it prone to cascading outages. These susceptibilities raise concerns about our reliance on our centralized grid in providing reliable power. While distributed generation is not a new concept, there have been proposals to develop microgrids, which are small-scale, self-regulating grids that can generate and distribute power locally. These microgrids would normally be connected with the centralized grid, but in an emergency situation could isolate themselves and continue serving its local area. Microgrids would also depend on smart grid technology to fully integrate on-site generation, demand response, and storage. If microgrids can achieve commercialization and demonstrate their reliability benefits, it may spur a rethinking of power system planning.
A third potential driver toward a less-centralized electricity grid is the potential coming increase in retail rates, as discussed in detail in chapter V of this report. As noted therein, the U.S. has enjoyed favorable conditions in several variables that drive electricity rates, from low natural gas prices to public subsidies for otherwise uneconomic generation and transmission. Those conditions could become less favorable over time, and when coupled with a forecasted increase in needed capital spending by utilities to modernize the grid and to achieve environmental compliance, retail rates could face persistent upward pressure for the foreseeable future. Perhaps no incentive toward decentralization is stronger than economic incentives for end users, and thus these rising retail rates could help push customers to consider distributed generation and other demand-side management programs to reduce exposure to retail rates. State and federal opportunities for demand-side management and distributed generation can amplify this economic incentive, perhaps changing the economics for some customers.
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LIST OF TABLES AND FIGURES Page
Table II.1 U.S. Lower 48 Employment Contribution for Unconventional Gas Activity (Number of Workers) 12
Table II.2 U.S. State-Level Employment Contribution of Unconventional Oil and Gas Summary (Number of Workers) for SPP Member States 13
Table II.3 Contribution from Unconventional Gas Activity to U.S. Lower 48 Government Revenue (Millions of 2012$) 14
Table II.4 Selected Scenario Results for 2035 18
Table III.1 Boston Pacific’s List of Environmental Regulations Impacting the Electric Power Sector 24
Table V.1 U.S. Utilities with Underfunded Pension Obligations 50
Figure II.1 NYMEX Futures Prices for the 2013 to 2025 Period on Two Trade Dates (Nominal Dollars per MMBtu) 11
Figure II.2 Excerpts from EPA’s Description of the Five Stages of the Water Cycle for Hydraulic Fracturing 16
Figure II.3 Change in Income Components and Total GDP in USREF_SD_HR (Billions of 2010$) 20
Figure III.1 Historical U.S. Greenhouse Gas Emissions (Million Metric Tons CO2 Equivalent) 30
Figure IV.1 Map of Midwest ISO, Entergy, and SPP Footprints 36
Figure V.1 Average U.S. Residential Monthly Bill (2011$) 44
Figure V.2 EIA Natural Gas Price Forecast 47
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GLOSSARY AC Alternating Current
Bcf Billion cubic feet
Boston Pacific Boston Pacific Company, Inc.
B&W Babcock & Wilcox
CAIR Clean Air Interstate Rule
California ISO California Independent System Operator
CBO Congressional Budget Office
CCR Coal Combustion Residuals
CFTC Commodity Futures Trading Commission
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent
CSAPR Cross-State Air Pollution Rule
CWA Clean Water Act
DC Direct Current
DOE U.S. Department of Energy
EIA U.S. Energy Information Administration
EGU Electric Generating Unit
EPA U.S. Environmental Protection Agency
ERCOT Electric Reliability Council of Texas
EV Electric Vehicle
FERC Federal Energy Regulatory Commission
FGD Flue-gas Desulfurization
FIP Federal Implementation Plan
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GDP Gross Domestic Product
GHG Greenhouse Gas
GW Gigawatt
HVDC High Voltage Direct Current
IEEE Institute of Electrical and Electronics Engineers
IHS IHS Global
IPL Interstate Power and Light Company
IRP Integrated Resource Plan
ISO Independent System Operator
ISO-NE ISO New England
JISEA Joint Institute for Strategic Analysis
kV Kilovolt
kW Kilowatt
LNG Liquefied Natural Gas
MATS Mercury and Air Toxics Standards
Mcf Million cubic feet
Midwest ISO Midwest Independent System Operator
MMBtu Million British Thermal Units
MW Megawatt
NAAQS National Ambient Air Quality Standards
NARUC National Association of Regulatory Utility Commissioners
NERA NERA Economic Consulting
NERC North American Electricity Reliability Corporation
NGV Natural Gas Vehicle
NOx Nitrous Oxide
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NPDES National Pollutant Discharge Elimination System
NSPS New Source Performance Standards
NYISO New York Independent System Operator
NYMEX New York Mercantile Exchange
PG&E Pacific Gas & Electric Company
PJM PJM Interconnection, LLC
PPA Power Purchase Agreement
ppb Parts-per-billion
PSD Prevention of Significant Deterioration
PSO Public Service Company of Oklahoma
PV Photovoltaic
RFF Resources For the Future
RFP Request for Proposal
RGGI Regional Greenhouse Gas Initiative
RPS Renewable Portfolio Standards
RTEP Regional Transmission Expansion Plan
RTO Regional Transmission Organization
SCADA Supervisory Control and Data Acquisition
SIP State Implementation Plan
SMR Small Modular Reactor
SPP Southwest Power Pool
SPP GETF SPP Grid Exercise Task Force Sulfur Dioxide
SO2 Sulfur Dioxide
Tcf Trillion Cubic Feet
WECC Western Electricity Coordinating Council
